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Day-ahead market and other market changes proposed for Alberta's electricity system

Alberta has shared the proposed comprehensive reforms to its electricity sector and an ambitious timeline for implementation.

The proposed changes

The design recommendations are headlined by the announcement of a day-ahead market, in addition to other significant market design changes including: introducing offer mitigation with a low price cap to mitigate extreme price events; administrative scarcity pricing, high price cap and negative floor price; additional ancillary service products, ramp-up reserves, strategic reserves and enhanced technical requirements; co-optimization of dispatch of energy and ancillary services; shorter settlement intervals; and security constrained economic dispatch.

More generally, the proposed reforms include better distribution system planning, priority for self-supply and energy storage, and enabling export potential with projected supply surpluses across the interties with neighbouring jurisdictions. The reforms commit Alberta to an energy only market, deliberately moving away from a capacity market design. While a Crown corporation option was considered, this has been classified a last resort for the time being. Similarly, adopting a long-term or integrated planning model was shelved as a near-term option, with the potential to revisit after more immediate policy intervention has been given the opportunity to take effect.

Motivations for change

Collectively, the proposed reforms are positioned as responsive to recent electricity supply shortfalls in Alberta, with stated objectives of reliability, affordability, decarbonization by 2050, and reasonable implementation.

Beyond these objectives, the Government referenced various policy considerations, both past and present. Looking back in time, the supply mix was dominated by coal, has since undergone iterative design changes to evolve the supply mix, and has recently experienced price volatility and scarcity of supply during winter peaks. Presently, there is a perceived shortfall of baseload generation and over-reliance on intermittent resources, market design inefficiencies, and uncertainty following the renewal generation pause.

Development and implementation

The development and implementation of the proposed reforms will leverage existing regulatory and technical expertise at both the Alberta Electric System Operator (AESO) and the Market Surveillance Administrator (MSA), as described in the letters from Minister of Affordability and Utilities Nathan Neudorf to each organization on March 11, 2024. These Ministerial letters form part of a continuing policy mandate that recently delivered:

  1. the AESO Recommendations to the Minister of Affordability and Utilities, titled “Alberta’s Restructured Energy Market”, published by the AESO on January 31, 2024; and
  2. the Confidential Advice to the Executive Counsel and the Minister of Affordability and Utilities, titled “Advice to support more effective competition in the electricity market: Interim action and an Enhanced Energy Market for Alberta”, published by the MSA on December 31, 2023.

Minister Neudorf’s March 11 letters to the AESO and MSA action the findings of both reports and accelerate instructions for policy changes. As a central mandate, the Minister actions the AESO recommendation for a “Restructured Energy Market” (REM) by issuing instructions to the AESO to prepare a technical design proposal, and by requesting the MSA to work with the AESO to engage industry stakeholders for this purpose.

There is a preference for preserving Alberta’s competitive market-based structure for wholesale electricity, while considering the ability to introduce procurement contracts if determined necessary, in consultation with stakeholders and an Executive Working Group. The AESO’s January 31 report concludes “the development of generation through any form of contract will negatively impact the efficiency outcomes of the wholesale market and the long-term investment signal”, and that any out of market action “should have a clear and fixed boundary on how capacity should be procured”. The AESO also considered the potential for the Clean Electricity Regulations (CER), as currently proposed, to introduce market uncertainty and negatively impact the long-term investment signal. The AESO suggested that Alberta could support specific technologies for which private equity would have difficulty taking financial and regulatory risk (such as nuclear resources) or could manage the legal liability of accelerated federal emissions reduction requirements.

Briefly, the REM proposes a phased implementation comprised of:

  • Near-term objectives over six months to two years that would:
    • establish an interim market power mitigation framework focused on limiting the offer prices of large generation suppliers once a sufficient revenue threshold to recover fixed costs is met;
    • pursue additional operational actions to commit generation units for reliability;
    • procure additional reliability services from dispatchable assets;
    • enhance technical requirements to mitigate intermittency of supply;
    • procure services to increase intertie capability for further access to neighbouring jurisdictions; and
    • take other actions as needed to support system reliability.

The near-term objectives are intended to introduce affordability and reliability solutions in the immediate term while more complex REM reforms are contemporaneously advanced.

The Government recently acted on the first of these near-term objectives by enacting a regulation restricting economic withholding by large generators through late 2027.

  • Medium-term objectives over two to five years that would:
    • introduce a day-ahead market to provide additional certainty for generation and incentivize the availability of controllable generation;
    • replace economic withholding with administrative scarcity pricing mechanisms as the fixed cost recovery mechanism for suppliers;
    • increasing the price above $1,000/MWh in limited supply scarcity situations to support long-term investment and ensure fixed cost recovery;
    • include a price cap mechanism once reasonable fixed cost recovery is met to protect consumers from excessive costs;
    • implement improved dispatching tools for the efficient and reliable dispatch of resources reflecting various constraints on the system and minimizing costs;
    • co-optimizing energy and ancillary services to mitigate costs and enable reliability;
    • shorten settlement intervals and implement negative pricing to improve price signals for flexible generation, controllable demand, intertie transactions, and storage; and
    • modify the Transmission Regulation and the ISO tariff to improve locational signals for siting generation and allocate costs by causation.

The medium-term objectives are intended to progress REM design changes that further augment the market by providing incentives for investment in dispatchable technologies and demand response, mitigating price volatility, and improving grid operation and utilization of the transmission system.

  • Longer-term objectives beyond five years that would:
    • monitor the adequacy of supply and seek to incent the development of controllable generation, rather than pursue longer-term contracts or an integrated or centralized resource planning model, absent a strong need for such changes, and based on current AESO adequacy studies that indicate sufficient supply over the next decade.

Lessons from Ontario

Taking a momentary step back to contextualize, it would be remiss to overlook the Ontario experience. Nuances aside, only Ontario and Alberta have competitive wholesale electricity markets in Canada. Ontario is presently approaching the anticipated 2024 implementation date for a day-ahead market as part of its Market Renewal Program. That reform program was initiated in 2016 and was preceded by another unsuccessful attempt to introduce a day-ahead market in 2006. Ontario’s experience offers some perspective for Alberta:

  • First, expect complexity. Like the Ontario reforms, the proposed reforms to the Alberta electricity market are fundamental and potentially extensive. They are unlikely to be simple to implement on either the conceptual or the technical level. This is a lesson not only from Ontario but also from Alberta’s own recent flirtation with a capacity market, which initiative was abandoned by the current Government after three years of studies, consultations and rule development.
  • Second, maintaining stakeholder engagement can decide the success or failure of the initiative (or somewhere in between, which is sometimes worse). In Ontario, the IESO’s phased development has engaged stakeholders on the benefits case, policy scope, market rule making and administration, high level designs, detailed designs, and draft market rules and manuals. There have been some contentious moments, such as cancellation of the incremental capacity market design, and with the implementation stage now imminent, there is a mix a stakeholder fatigue and anticipation after investing eight-years in the process. Meanwhile in Alberta the last attempt at major market reform was characterized by intense scrutiny from stakeholders, and it remains to be seen how the Government will approach the current round of reforms.
  • Third, once invested it’s difficult to look back. It has been eight years since Ontario initiated its Market Renewal Program, and it is only now transitioning from the design phase to the implementation phase. The IESO and stakeholders have invested heavily in seeing this second attempt at a day-ahead market take effect and have perhaps pushed past the point of no return, in a tacit and tenuous now or never alliance. By contrast, Alberta is embracing an explicit past the point of no return mandate for the design and implementation of its proposed reforms, including temporarily shielding ISO rulemaking from appeals in an effort to impose market stability amidst uncertainty. Once such rules are in place to implement the proposed reforms, it will be very difficult for this or any future Government to reverse course – particularly if those rules contemplate long-term contracts, as discussed below. Stakeholders’ need for certainty will need to be carefully balanced against the Government’s need for policy flexibility, and significant implementation delays could end up working against both.

Timeline and mechanism for the proposed market reforms

The proposed Alberta reforms would proceed by detailed design, further industry consultation to determine the specific design and implementation details, ISO rule revisions, market participant education and training, and new or modified information systems and AESO processes. The detailed design would be launched in 2024, and progress on the timeline identified on page 36 of the AESO report as follows:

Near-term implementation:

2024: Phase 0 – Market restructure recommendation
2024: Phase 1 – Await policy decision, scope of initiatives, determine design work groups based on recommendation
2024: Phase 2 – Determine detailed design options aligned with policy direction
2024-early 2025: Phase 3 – Evaluate detailed design options aligned with policy direction

Next phases:

Early 2025: Phase 4 – Finalize detailed design and recommendations
2025-early 2026: Phase 5 –  Rule filing and AUC disposition
2025-2026 and beyond: Phase 6 – Information system implementation and market change management

A strategic objective informing this momentum is the AESO recommendation that the proposed reforms will be most effective if implemented in their entirety, as many are interrelated and must work in combination to achieve reliable and efficient market outcomes.

Given the compressed timeline for developing and implementing comprehensive reforms, a persistent process risk will be delay and the rapid pace of change. Delays may compel the selection of certain choices, such as introducing long-term contracts (a perceived point of no return for Alberta), or policy mandates may become stale dated due to disruptive technologies, evolving economic conditions, or incentives in competing jurisdictions. Excessive delay may create an industry perception that the policy initiative is too big to fail, and stakeholders may become overwhelmed, disengaged, or divergent in interests. Comparatively, it is Alberta’s objective to build investor confidence and diminish risk premiums by using these reforms to rally and reassure stakeholders.

To manage risk associated with delay, a hybrid approach to the implementation of design changes is proposed, comprised of six phases, as set out in the graphic from page 36 of the AESO report as follows:

Phase 1

Minister to review the AESO's recommendation and advise on the policy direction.

Phase 2

AESO will develop proposed design options while adjusting for the policy decisions once they are available.

Phase 3

Feedback on design options from industry stakeholders.

Phase 4

Develop the detailed design by drafting ISO rule and tariff changes (if required) utilising the stakeholder process initiated in Phase 3.

Phase 5

Development and filing of the rule application with the AUC, and the AUC's process to hear the application and issue a disposition. Further, details on regulatory changes required to complete this phase are provided in the next section.

Phase 6

Implement the rules within AESO systems and processes. Phase 6 is expected to take 18 to 20 months to design and implement the necessary systems required to operate the REM and may need to be adjusted to accommodate additional AUC directions. The AESO will focus on implementing the foundational market components first. Additional time beyond 2026 may be required to phase in more complex elements to de-risk overall implementation and ensure foundational components are in place by 2026.


The AESO determined that the current ISO rule approval process would hinder the efficient implementation of the comprehensive design changes on the timelines proposed, and “that a different process is needed to efficiently implement clear and specific policy direction for significant structural change” (page 38). The hybrid approach or alternative process proposed by the AESO would shield a decision of the Commission from appeal for a period of 18 months, to insulate the newly approved ISO rules and allow them to be tested in practice and would further preclude parties from filing complaints about the approved ISO rules during this period. As precedent for this approach, the AESO references the capacity market initiative, which also prescribed a special ISO rules approval process.

Separate from anticipated ISO rule changes, legislative changes are expected to be required to implement the proposed reforms to the Electric Utilities Act and related regulations, including the Transmission Regulation, and the Fair, Efficient and Open Competition Regulation (FEOC).

With a proposed fall of 2024 timeline for delivery of a first draft of the technical design, it will be a very busy spring and summer for the AESO, MSA, and participating stakeholders, who will be contemporaneously negotiating more immediate interim measures.


Representatives across the stakeholder community should dedicate sufficient resources on an immediate basis to remain current, perform independent due diligence, identify any unique challenges, explore coalition building with other stakeholders or industry groups, and provide meaningful feedback to the AESO over the course of the engagement or multiple staged engagements.

Key Contacts