Alberta Built a World-Class Carbon Market. Policy Uncertainty Now Puts It at Risk

By Paula McGarrigle, President & CEO, Solas Energy

Alberta has long enjoyed a reputation, deservedly so, as the unlikely pioneer of industrial carbon pricing in North America. When the Specified Gas Emitters Regulation (SGER) took effect in 2007, Alberta was years ahead of its time. It built quantification methods, verification processes, registries, and compliance rules by leaning on international standards and precedence. It wasn’t perfect, but it worked. In a “good-better-best” hierarchy, SGER landed squarely in “good”: functional, measurable, improvable.

By the early 2010s, Alberta’s bureaucracy was even drafting a far more ambitious “SGER 2.0.” Political turnover prevented its launch, but the point stands: Alberta had designed and operated a credible carbon-market system before most jurisdictions had even begun discussing it.

Under SGER, the carbon price was capped at just $15 per tonne. At that level, no one expected carbon pricing to transform Alberta’s power sector — and it didn’t. Alberta’s strategy at the time was clear: protect the “golden goose” while using targeted out-of-market subsidies, rather than price signals, to drive reductions. This is how major projects like Quest (Shell’s carbon capture and storage project) were funded. Alberta initially relied on intensity standards and subsidized technology deployment, not high carbon prices, to deliver early reductions.

What unlocked renewable energy in Alberta was not the carbon price, but the emergence of long-term offtake structures: first through the Renewable Electricity Program and its Renewable Electricity Support Agreements (RESAs), and later through large corporate PPAs that provided the revenue certainty needed for true bankability.

Offsets did play a role, but primarily at the margins: they added incremental revenue that helped projects pencil out, particularly during periods of price volatility. In other words, offsets made renewables more financeable, but they were not the foundational driver of Alberta’s renewable boom.

As electricity prices began to fall in the mid-2010s, driven by oversupply, low natural gas prices, and merit-order effects, the economics of renewable energy shifted again. That widening spread between falling electricity prices and rising carbon prices changed renewable energy project economics. Carbon credit revenue went from “icing on the cake” to a meaningful component of offtake agreements, with EPC and offset value explicitly baked into PPA negotiations and financial models. In several cases, carbon revenue became the difference between a project that was merely interesting and one that was investable.

Fast forward to today. Alberta finds itself at a crossroads, caught between its history of innovation and a new period of policy volatility that risks undermining the credibility of its carbon market at the precise moment global investors are demanding stability, transparency, and verifiable reductions.

This is the story of how we got here, why it matters, and what comes next.

A Market Once Built on Stability Now Faces Structural Fractures

By 2023, Alberta’s carbon market began showing signs of deeper weakness. Several policy decisions amplified the imbalance between supply and demand:

  • Shorter credit expiry periods released older credits back into circulation.
  • Increased offset/EPC use-limit caps added more supply to an already saturated market.
  • Public and political backlash against consumer carbon pricing dampened compliance-buyer confidence.
  • Federal initiatives such as the Pathways Alliance proposals for Carbon Capture, Utilization and Storage influenced expectations about long-term supply and demand.

Meanwhile, inexpensive projects, especially pneumatic-device offsets, kept generating large volumes at very low cost. Developers were willing to sell cheaply; traders arbitraged aggressively. The result: a chronically depressed carbon price.

When the federal government eliminated fuel carbon charges for consumers in spring 2025, many facilities previously opted-in Technology Innovation and Emissions Reduction Regulation (TIER) reconsidered participation. Their demand for offsets fell. Prices dropped further.

By early 2025, Alberta’s carbon price was trading well below $30/tonne.

And then came the freeze.

The $95 Freeze: Competitiveness Protection, or Market Signal Breakdown?

In May 2025, the Province froze the TIER carbon price at $95/tonne, despite the Supreme Court of Canada’s explicit ruling that carbon pricing is a matter of national concern firmly within federal jurisdiction. Alberta fought the federal system and lost; it did not “miss the memo.”

The Provincial government justified the freeze on competitiveness grounds, citing U.S. tariffs and protectionist trade actions. Yet the tariff discussion obscures a key fact:

Alberta’s primary export to the United States, crude oil, faces no tariff when properly documented as CUSMA-origin.

Electricity faces none.

If the goal were to address competitiveness concerns directly, the Province had other, more effective tools. For example:

Recycling 100% of TIER Fund revenues back to emitters and decarbonization projects, rather than diverting a portion to general revenue, would have provided immediate relief without compromising market integrity.

But the freeze also aligned with the Province’s broader goal, made explicit in the October 2025 Speech from the Throne:

“Your government will not rest until Alberta has doubled its oil and gas production.”

This declaration, delivered alongside a photo of the retreating Crowfoot Glacier, symbolized the tension between Alberta’s stated long-term climate aspirations and its near-term production ambitions.

A New Compliance Pathway: The Direct Investment Program (DIP)

In this environment, Alberta introduced the Direct Investment Program (DIP), allowing TIER-regulated facilities to reduce obligations by investing directly in emissions-reduction projects at their own sites.

In concept, DIP sounds familiar and is similar, the Province argues, to how TIER Fund revenues support decarbonization projects through Emissions Reduction Alberta.

In practice, DIP diverges sharply from Alberta’s established offset and EPC system:

  • Offsets and EPCs must meet Quantification Protocol standards foundationally based on ISO 14064.
  • DIP projects have no published requirements for additionality, permanence, measurability, leakage, or third-party verification.
  • Two identical projects could be treated completely differently depending only on whether the facility is TIER-regulated.

This creates an uneven playing field: compliance flexibility for some facilities, subsidization for others, and uncertainty for everyone else.

Worse:

Government communications imply that a $95 investment may simply equal one tonne of compliance, without transparent quantification rules.

If true, DIP could become less a carbon-market instrument than a parallel subsidy program—bypassing the transparent standards that have defined Alberta’s credibility for nearly two decades.

Why This Matters: The 2026 Federal Benchmark Test

In April 2026, the federal government must determine whether Alberta’s system meets the minimum requirements of the federal carbon-pricing benchmark.

The benchmark requires:

  • A rising carbon price aligned with the federal trajectory
  • A functioning market producing credible tonnes
  • Compliance mechanisms that deliver real verifiable reductions

If Alberta fails the test, the federal Output-Based Pricing System (OBPS) under the Greenhouse Gas Pollution Pricing Act (GGPPA) applies automatically.

This would be seismic.

Under the federal OBPS:

  • Offsets and emission performance credits (EPCs) from regulated sectors are not allowed.
  • Offsets and EPCs would instantly lose value.
  • Renewable generators, especially wind and solar, would lose a significant revenue stream.
  • Industrial emitters would lose lower-cost compliance options.

Roughly 9 GW of renewable generation in Alberta, 40% of the grid capacity, would face revenue reductions overnight.

Investors, lenders, and developers have taken these risks seriously in other jurisdictions. Alberta will not be an exception.

GHG Protocol, ISSB, and the Investor Credibility Problem

Global capital markets are rapidly converging on stringent climate-disclosure frameworks, including the International Sustainability Standards Board’s Climate Disclosure Standard (ISSB–IFRS S2), the European Union’s Corporate Sustainability Reporting Directive and ESRS standards (EU CSRD/ESRS), and the U.S. Securities and Exchange Commission’s proposed climate-disclosure rules.

All effectively require reporting based on GHG Protocol Corporate Accounting and Reporting Standard (GHG Protocol).

If DIP projects do not produce real, additional, verifiable reductions, Alberta may inadvertently create “reductions” that:

  • cannot be counted toward corporate Scope 1, 2, or 3 targets,
  • cannot be reported under ISSB, CSRD, or SEC rules,
  • cannot support investor-grade decarbonization claims.

That is not a theoretical risk.

That is a material governance and disclosure risk—for boards, CFOs, and investors.

Conclusion: Alberta Needs Market Stability, Not Market Confusion

Alberta has stated its ambition to decarbonize by 2050 and to shift away from reliance on non-renewable resource revenue. That vision requires investment, and investment requires stability.

Right now, Alberta is offering neither.

Instead, the Province has created:

  • A fixed carbon price disconnected from market conditions
  • A depressed offset/EPC market
  • A new compliance pathway with undefined rules
  • A rising risk of failing the 2026 federal benchmark
  • A credibility challenge for issuers reporting under the GHG Protocol

A predictable, stable, credible carbon-pricing system, backed by verifiable reductions, is not only compatible with Alberta’s long-term economic vision; it is essential to it.

If Alberta wants investment, it must send investable signals.

Because right now, the market is getting mixed messages.

Developers, project financiers, and large industrial emitters rely on Solas Energy to quantify carbon-market exposure, forecast EPC/offset revenue, and design resilient decarbonization and compliance strategies. If your assets or investments depend on Alberta’s carbon-pricing system, we can help you understand the risks, and the opportunities, emerging from this evolving policy landscape.