Alberta’s CCS Protocol Update: Why Direct Air Capture, Low-Carbon Power Accounting, and Storage Liability Matter for Global Carbon Buyers

What Alberta is changing in its CCS quantification protocol

Alberta has published a new draft update to its CCS quantification protocol, and the direction is clear: the framework is moving beyond traditional industrial CCS toward higher-integrity carbon removal, including DACCS and removal credits.

The draft, released in May 2026, updates the “Quantification Protocol for Carbon Dioxide Capture and Permanent Geologic Sequestration v2.1.” For buyers, that matters because it signals a protocol that is no longer just about captured emissions from industrial sources. It is now being shaped for engineered removals as well.

The update also introduces an explicit pathway for direct air capture projects. That includes rules on how eligible projects may claim electricity generated by a low-carbon intensity project, provided the conditions are met. For lifecycle accounting, this is a big deal. It affects how net removals are measured and how double counting risks are managed in removal portfolios.

Alberta is also tightening documentation requirements for “Flexibility Mechanism 1 projects.” In addition, the draft includes an example of “reversal error correction accounting” when multiple sources inject into the same well. That is not a minor technical detail. It is the kind of rule that affects traceability, MRV, and how operators and verifiers assign responsibility.

The province already has real market weight behind it. By May 2025, Alberta says projects had permanently stored more than 15 million tonnes of CO2 through CCS and EOR. That gives the regulatory system more credibility for international buyers who want evidence that the framework is not just theoretical.

For developers and buyers, the main issue is not simply that the rules are changing. It is that protocol design, registry treatment, and eligibility criteria for tradable credits are becoming more tightly linked. That is especially important for DAC, where electricity accounting can make or break the net removal case.

Why low-carbon electricity accounting is becoming a key issue for DAC projects

Energy use is one of the main drivers of DAC’s lifecycle carbon footprint. The IEA is clear that access to renewable or low-carbon electricity for heat and power is critical if DAC is going to deliver strong net removals.

That is why Alberta’s update matters. The draft allows, under conditions, DAC projects to attribute electricity from a low-carbon intensity project to the removal activity. For buyers, that changes the implied price per net tonne and the strength of the additionality story.

This is also where due diligence gets more serious. The IEA notes that DAC services are currently sold mainly in the voluntary carbon market, and that policy support depends increasingly on robust accounting frameworks and credible LCA methods. In other words, the energy source is not a side issue. It is part of the credit quality.

Commercially, DAC removal contracts are often signed by large buyers or aggregators, and the IEA points to historical prices of roughly 600 to 1,000 USD per tonne of CO2 for DAC with geological storage. If the electricity is genuinely low-carbon, the net-to-gross crediting logic becomes easier to defend with investors and auditors.

The practical question is not just how much energy the project uses. It is how the project proves that the energy does not erode net removals or shift emissions somewhere else. That leads directly to the next issue: reversals, liability, and integrity.

How removal credits and storage reversals affect credit integrity and liability

Alberta’s update matters because it is treating removal credits more explicitly, including those from DAC and biogenic CO2, and it is clarifying how reversals should be handled.

That is important for institutional buyers. The draft includes an example of reversal error correction accounting for multiple injections into the same well. That suggests Alberta is strengthening the rules around attribution, operator responsibility, and storage-site accounting.

Liability is where Alberta stands out. The province’s framework allows the government to assume long-term liability for storage sites, supported by mandatory contributions to the Post-Closure Stewardship Fund. For buyers, that reduces the risk of stranded permanence.

This is a core integrity issue. Strong MRV, clear storage-zone definitions, and a clean distinction between net reversals and post-crediting events all affect whether a credit can be insured, financed, and sold forward with confidence.

For a corporate issuance or a carbon removal portfolio, the operational question is simple: who carries the residual risk if the stored CO2 does not remain permanent as promised? Alberta’s framework is trying to answer that more clearly than many markets do.

What the update could mean for project developers, emitters, and investors

For project developers, the update raises the bar on design-by-compliance. Interconnection, proof of low-carbon electricity, well boundary definition, monitoring plans, and reversal documentation need to be built into the project early, not patched in later.

For emitters buying credits, the update could improve the perceived quality of removal contracts. It reduces ambiguity around net removals, attributed electricity emissions, and permanence. That matters for buyers with net-zero targets, SBTi-aligned portfolios, or carbon neutrality claims.

For investors, the signal is that Alberta wants carbon removal to be more financeable. The province already has support mechanisms such as the ACCIP, plus a regulatory model built around sequestration hubs, infrastructure networks, and a public registry.

Alberta is also continuing to develop tenure and hub storage through updated consultations and calls for proposals in 2025 and 2026. That points to a regulated pipeline that can support offtake agreements and project finance across multiple assets or hub-based structures.

In practice, the new protocol can affect valuation, PPA strategy, insurance pricing, and lender covenants. Credit quality now depends more clearly on energy, storage governance, and post-closure liability.

Why Alberta’s approach matters beyond Canada for carbon removal markets

Alberta is often watched as an international benchmark because it combines regulation, storage geology, and a live carbon credit market. The province says it is a global leader in CCUS and has invested or committed nearly CAD 1.8 billion in CCUS projects and programs.

For global buyers, the value of the update is not just local. The IEA has stressed that DAC and carbon dioxide removal need robust accounting frameworks if they are going to work credibly across voluntary and regulated markets.

That makes Alberta’s rules on low-carbon electricity, removal credits, and reversals potentially important beyond the province itself. They could become a reference point for standard setters, registries, and market operators looking for more consistent DAC methodologies.

The global market still needs credible benchmarks. The IEA notes that DAC removal contracts remain concentrated in the voluntary market, are often oversubscribed, and tend to be expensive. That makes well-designed provincial frameworks a competitive asset for attracting international demand.

The key takeaway is simple. Alberta is turning its CCS protocol update into a market design tool. If the model holds up on energy, permanence, and liability, it could offer a useful blueprint for carbon removal markets elsewhere.