Power Perspectives 2026: Alberta Regional Overview

This article originally appeared as a chapter in our Power Perspectives 2026 publication and provides a look back at some of the key developments in the power market occurring in 2025. Power Perspectives 2026 provides an in-depth overview of the most significant developments in the Canadian power and emerging energy sectors. Where applicable, we have noted some of the updates to these topics that have occurred so far in 2026.

Introduction

2025 marked another year of change in the Alberta power industry. Alberta continues to face a major electricity market overhaul through both updates to the Optimal Transmission Planning (“OTP”) and Restructured Energy Market (“REM”), which focus on building a stable, reliable, and affordable system for energy generation and transmission. 2025 also brought greater market certainty through significant stakeholder engagement, final REM design and clearer steps for implementation. Further developments in 2026 are expected, which may have broad impacts on electricity market proponents.

These changes were further complemented by initiatives to improve the data center market in Alberta, driven largely by the Alberta Electric System Operator (“AESO”), and proposed amendments to Alberta’s emission reduction system that are intended to improve competitiveness and attract investment. The landmark Memorandum of Understanding (“MOU”) signed by Prime Minister Mark Carney and Alberta Premier Danielle Smith on November 27, 2025, and discussed further by our team in a blog post here, will help to propel this theme of continued change into 2026 and beyond as the various commitments are implemented by both levels of government.

Key Developments in 2025

Alberta-Canada Memorandum of Understanding

On November 27, 2025, Alberta and the federal government entered into an MOU that promises to further Canada’s energy competitiveness. The MOU is centered on a shared goal of enhancing economic growth, achieving carbon neutrality by 2050, and establishing the nation as a global leader in both conventional and clean energy. Under the MOU, the provincial and federal government announced two integrated major projects: (1) the Pathways Plus carbon capture, utilization, and storage (“CCUS”) project, paired with (2) a new pipeline to the northwest coast of British Columbia designed to facilitate delivery of low-emission oil to Asian markets. This marks a commitment from both levels of government to ensure Canadian oil exports remain competitive and sustainable. Several additional promises that were included in the MOU may impact future energy market projects, including:

1. Alberta’s commitments to reduce methane emissions by 75% over the next decade, develop a nuclear power generation strategy, and incentivize artificial intelligence (“AI”) data center projects in the province (as discussed below);
2. a commitment from both parties to develop large transmission interties with British Columbia and Saskatchewan to deliver low-cost, low-carbon power across provincial borders; and
3. a shared objective to ensure that projects under the MOU provide meaningful opportunity for Indigenous communities to participate in consultation and economic benefit through co-ownership and partnerships.

One of the stated objectives of the MOU is to address affordability, stability, competitiveness, and certainty through electricity and energy policies. Of importance to the power market, the MOU included clarification and improvement to the regulatory environment. The federal government agreed to exempt Alberta from the Clean Electricity Regulations on the condition that a new carbon pricing agreement is made between the two jurisdictions. This agreement will aim to achieve emissions reductions targets and provide certainty to industry by establishing a framework for effective carbon pricing. As part of this commitment, Alberta agreed to increase its previously frozen industrial carbon price under its technology innovation and emission reduction (“TIER”) system to federal standards and work collaboratively with the federal government to establish an agreed industrial carbon price. The new carbon pricing agreement is to be completed by April 1, 2026. As part of these commitments, the federal government agreed to “enable decarbonization of the electricity system, while ensuring its reliability and affordability” in collaboration with Alberta. Additional commentary was provided by both Premier Danielle Smith and Prime Minister Mark Carney after the signing of the MOU, which is discussed further in a blog post here.

2026 Updates

While the new carbon pricing agreement between Alberta and Canada remains outstanding, some progress has been made on other commitments under the MOU. On March 25, 2026, Canada and Alberta announced an Agreement in Principle on a Canada-Alberta methane equivalency agreement and on April 2, 2026 Canada and Alberta entered into a Co-operation Agreement on Environmental Impact Assessment.

Alberta’s Restructured Energy Market

Background

On August 2, 2023, the AESO and the Market Surveillance Administrator were directed, pursuant to an order-in-council, to prepare a comprehensive report on market reforms to the electricity system and deliver this report to the Minister of Affordability and Utilities (“MAU”). This work focused on market incentives, energy market design, and the integration of new technologies.

On March 11, 2024, MAU directed the AESO to begin drafting the technical design for the REM, proposing a phased approach that included the Day-Ahead Commitment (“DAC”) market. On July 3, 2024, the MAU issued a direction letter to the AESO directing it to proceed with REM, followed by an additional direction letter on December 10, 2024. During stakeholder consultations and REM design finalization sessions in April 2025, significant concerns emerged regarding the risk of over procurement and increased costs from rigid administrative pricing in the DAC market and the AESO elected not to proceed with the DAC.

On May 15, 2025, the Energy and Utilities Statutes Amendment Act, 2025 was enacted amending the Electric Utilities Act to enable the REM, including new constructs for a day-ahead market and a real-time market, and a broader framework that expressly included ancillary services procurement and transmission constraint management. It also empowered the MAU to establish REM Independent System Operator Rules (“REM ISO Rules”) by regulation and provided that such rules can take effect without approval from the Alberta Utilities Commission (“AUC”). Following extensive consultation sessions, on August 27, 2025, the AESO released its final design for the REM.

Key Features of the Final REM Design

The final design of REM was guided by four main objectives: reliability, affordability, decarbonization by 2050, and reasonable implementation. Key components of the final design are designed to facilitate the involvement of smaller generators in the market and enable greater competition, enhance price responsiveness and demand-side engagement, promote flexibility and efficiency in market operations, create a more stable distribution network, and ensure reliable system operation.

There are several key features of the AESO’s final REM design:

1. Market-Based Congestion Management

The AESO is implementing Locational Marginal Pricing (“LMP”), which will allow energy prices to vary by location, reflecting the value of energy and transmission constraints. Loads will continue to settle at a uniform price, but eligible loads can opt into nodal pricing within the first year of REM implementation (for existing assets) or during registration (for new assets connecting after REM implementation). The AESO suggests this approach encourages efficient use of the grid, guides investment to high-value locations, and reduces the need for costly transmission expansion.

2. Updated Pricing and Broad Market Power Mitigation

The AESO will increase the offer cap to $1,500/MWh with a price cap of $3,000/MWh. By 2032, the offer cap is projected to reach $2,000/MWh while the price floor will drop to -$100/MWh. These changes aim to strengthen investment signals, attract supply and demand responses, and enhance flexibility.

Additionally, as discussed in our previous blog post, a secondary offer cap will apply to generators with 5% or greater market share offer control that is triggered if revenue exceeds the threshold. This is meant to provide broad market power mitigation by imposing guardrails against the excessive exercise of market power.

3. Day-Ahead Reliability Market

The AESO made several key enhancements to the current day-ahead market for operating reserves including hourly procurement, co-clearing operating revenues, and clearing prices at the marginal offer for active reserve, but the market will continue to use indexed pricing. These changes are intended to promote competition for reliability products.

4. Real-Time Co-Optimized Ancillary Services

The AESO will implement a single real-time ramping product (“R30”) to compensate resources for ramping capabilities. The R30 demand curve will set procurement volumes and scarcity value, capped at $3,000/MWh. The AESO indicates that co-optimization allows for balance between energy and R30.

5. Reliability Unit Commitment

The AESO revised its unit commitment process by implementing a supply cushion threshold at zero or below that triggers commitment if the anticipated supply is insufficient. The market will continue to rely primarily on self-commitment of generation, but the updated process is aimed at enhancing reliability and forward supply control.

6. Transition Mechanism for Incumbents

Finally, the AESO will use temporary financial transmission rights (“FTR”) to limit the impact of the implementation for incumbents who invested under the current framework. These will be phased out over 8 years.

Pursuant to a further direction letter issued October 6, 2025, the AESO solicited formal statutory declarations prior to December 1, 2025 from relevant project proponents currently in service and actively participating in the AESO connection process confirming that a final investment decision was made on or before July 9, 2025, for any project seeking recognition as an incumbent.

ISO Rules

The AESO prepared REM ISO Rules that are required for the implementation of the final REM design. The REM ISO Rules address a range of compliance issues, including information document governance, real-time dispatch algorithm and market pricing, reliability unit commitment details, R30 details, local market power mitigation, and allowable dispatch variance.

To ensure the REM ISO Rules align with the final design and are technically sufficient, the AESO engaged with stakeholders for feedback through November 2025, with the AESO publishing responses to feedback and blacklines of all rule changes. Feedback generally followed four themes: (1) oversight, governance, and transparency; (2) design integrity and market fairness; (3) implementation clarity; and (4) impacts to operations and market feasibility.

2026 Updates and Next Steps for REM Implementation

The AESO has released the timeline for REM implementation by receiving approval of the final REM ISO Rules by regulation, you can read more about this update here. On March 10, 2026, the MAU adopted Ministerial Order 035/2026 for the Restructured Energy Market ISO Rules Regulation (the “REM ISO Rule Regulations”) under the Electric Utilities Act. The REM ISO Rule Regulations reduce consultation and increase executive control, essentially centralizing decision-making. Importantly, the operational effect of the REM ISO Rules is not immediate, but will come into force in a phased manner, as fixed by the AESO on 30 days’ advanced notice.

Optimal Transmission Planning Updates

Background

In a July 2025 letter (the “July Directive”), the MAU, in line with the Government of Alberta’s policy changes aimed at improving reliability, affordability, and sustainability, directed the AESO to shift from a zero-congestion planning approach to a modern-benefit driven approach. On July 9, 2025, the Transmission Regulation was updated to repeal and replace the requirement of a congestion-free transmission system with a requirement to “make arrangements for the expansion of the transmission system if the ISO determines that the overall benefits of the proposed development outweigh its overall costs.”

In response to the July Directive and the Transmission Regulation updates, the AESO began developing the OTP Framework ( “OTP Framework”), which prioritizes cost-effective, benefit-driven transmission development. The OTP Framework aligns with the Government’s affordability goals and the Transmission Regulation updates, emphasizing transparency, predictability, and practicality while ensuring system reliability and compliance with laws and Alberta’s reliability standards.

The OTP Framework aims to deliver several substantive benefits to Alberta’s electricity system including improved economic efficiency, enhanced grid reliability and comprehensive stakeholder engagement. A cost-benefit approach to project assessment is intended to ensure infrastructure projects are undertaken only when they provide clear net value to the electricity system. Projects are to be assessed holistically to address future uncertainties and risks and support the planning process to maintain compliance with reliability standards, improve efficiencies and enhance affordability, reliability, and long-term sustainability across Alberta’s electricity system.

OTP Framework Recommendations

On September 24, 2025, the AESO published its OTP Framework Recommendation paper (“OTP Framework Recommendation”). The framework provides guidance for the development of the Long-Term Transmission Plan (“LTP”) that aligns with the AESO’s directive. In the OTP Framework Recommendation, the AESO details the key steps of the OTP process as follows:

1. Forecasting: Forecasting for diverse 20-year scenarios to cover various economic, technological and policy drivers, to support prudent infrastructure decisions.
2. Modelling: Applying both a Zonal Model for generator capacity expansion and a Nodal Model that integrates detailed system topology for security-constrained dispatch simulations. This ensures accurate quantification of economic benefits and supports grid reliability assessments.
3. Transmission System Analysis: Utilizing simulation outcomes to identify needs for system projects. These are categorized as reliability, economic, legislated or multi-value, allowing for flexible and comprehensive planning.
4. Cost-Benefit Analysis: Systematically quantifying the full range of project benefits and costs from a system perspective. Key benefits of the OTP Framework Recommendation include avoided electricity production costs, deferred or avoided investments in new generation and transmission assets and reduced maintenance expenditures. This results in optimized allocation of capital and operational resources.
5. Project Development: Progressing recommended projects in the LTP for further optimization and stakeholder consultation, culminating in the preparation of a Need Identification Document for AUC approval.

A key change to the planning process is the introduction of economic and multi-value projects, and the cost-benefit analysis required to justify their need.

The OTP ISO Rule and Next Steps

As part of the next step of advancing the Framework, on October 24, 2025, the AESO put out a Letter of Notice for Development (“Letter of Notice”) of a Proposed New OTP ISO Rule (“OTP ISO Rule”). The AESO intends to use the OTP Framework Recommendation to develop an ISO rule and supporting information document (“ID”) to govern its OTP practice and transparent implementation of the OTP ISO Rule. The proposed stakeholder engagement approach includes consultation sessions, written feedback cycles, and information sessions.

The final OTP Framework paper was posted on January 30, 2026 and from stakeholder feedback from December 2025 to April 2026, the AESO will develop the OTP ISO Rule and ID requirements. It is our understanding that implementation is targeted for late 2026 through early 2027.

Looking Ahead: ISO Tariff

The ISO Tariff is the AESO’s rate schedule that governs how market participants pay for transmission services and access to the provincial grid. It sets out charges for demand and supply transmission service, opportunity services, and riders, along with detailed terms and conditions for connection and billing. These price signals influence investment decisions, grid reliability, and the integration of new technologies like storage and distributed generation.

The current tariff was updated on January 1, 2026, but a major redesign is underway to align with REM and OTP updates. Transmission Reinforcement Payment (“TRP”) design development occurred through April 2026, involving stakeholder engagement. The final AUC application for TRP is targeted for July 2026, which will be filed along with supply system access service, OTP, and tariff amendments for the AESO connection process.

This redesign aims to modernize cost allocation, improve transparency, and accommodate emerging technologies. Stakeholder engagement is planned to continue through 2026 and full implementation on connection cost responsibilities, billing frameworks, and regional rate design, ensuring the tariff supports REM’s principles of fairness and efficiency.

Generating Unit Owner’s Contributions Updates

In letters dated July 15 and October 6, 2025, the Government of Alberta directed the AESO to (1) allocate FTR transition payments to Market Participants (“MPs”) if they were recognized as an incumbent generator, or (2) refund the paid Generating Unit Owners Contribution (“GUOC”) if the MP cancelled its connection project.

GUOC Refund Eligibility

Following this direction, the AESO provided three primary criteria (“Criteria”) when determining eligibility for a refund of GUOC:

1. the GUOC must have been paid when the statutory declaration was submitted; projects that had not yet paid GUOC could cancel and get GUOC evidence returned, but had to do so before the Permit and License for the project was approved;
2. the required statutory declaration must have been submitted between October 15 and December 1, 2025, declaring the decision to cancel; GUOC refunds for size reductions were also considered if an entire source asset was removed; and
3. the project must not have been energized at the time of refund, otherwise the GUOC was refunded through the existing performance criteria framework (annually over 10 years).

Financial Obligations Due Upon Cancellation

Importantly, even when the Criteria was met and a GUOC payment was set to be refunded, the project remained responsible for other financial obligations, including the ISO Tariff and AESO fees, upon cancellation. Examples of these amounts include:

• projects that executed demand transmission service (“DTS”) agreements were subject to a Payment in Lieu of Notice Payment (“PILON”) for DTS reduction or termination under Section 5 of the ISO Tariff;
• Cluster 1 projects were subject to a reassessment fee upon cancellation;
• projects with effective supply transmission service contracts had forfeited annual GUOC payments that were not refunded; and
• customer contributions were adjusted for reduced local investment and TFO cancellation costs.

Timing of GUOC Refunds

In providing the GUOC refund, the AESO will issue the GUOC refund net of AESO fees. Further, the following must occur before the AESO can issue GUOC refunds:

• PILON and reassessment fees are paid, if the MP elected to pay before receiving a GUOC refund;
• all TFO and DFO cancellation costs have been settled; these may be applicable to the extent the construction of the transmission facilities have been completed; and
• the Transmission Regulation is amended by the Government of Alberta to allow the AESO to issue GUOC refunds outside of the existing ISO Tariff and legislative framework, which are expected in 2026.

Following a requested cancelation and verification by the AESO of eligibility, the System Access Service Request (“SASR”) will be cancelled. Going forward, if the project submits a new SASR, the connection alternatives will need to be re-assessed, and the connection process considered in Cluster 3 and beyond.

Update on Data Centres

The rapid growth of cloud-based services, computer and mobile applications, AI, machine learning technology, and other data-driven technologies is driving exponential demand for data storage infrastructure and corresponding demand for electricity to power such infrastructure projects. In Alberta, the government is actively promoting investment through its AI Data Centres Strategy, aiming to attract $100 billion in investments in the next five years and to establish the province as a leader in AI data centres. As part of this strategy, the government of Alberta announced, on August 27, 2025, that it will be introducing a levy framework for AI data centers, which became effective under Bill 12, Financial Statutes Amendment Act, 2025 (No. 2) on January 1, 2026. This levy framework effectively sets a timeline for the AESO to ensure the grid is integration ready for interested data-centre proponents. Additionally, in the MOU signed by Prime Minister Mark Carney and Premier Danielle Smith on November 27, 2025, the Province of Alberta has committed to implementing a policy framework that will incentivize large investments in data center development to further Canada’s computing sovereignty on or before July 1, 2026.

According to the AESO, there were 29 large-load connection requests in June 2025, largely from AI data centre projects, that represented over 16,000 megawatts (“MW”) of cumulative demand, compared to Alberta’s current peak load of approximately 12,000 MW.

Phase 1: Large Load Integration

On June 4, 2025, the AESO introduced Phase 1 of the Large Load Integration Program. This phase set out a one-time, interim limit of 1,200 MW for qualified project developers (“PD”), which represented the maximum additional large load capacity the grid could serve without negatively impacting reliability. All 1,200 MW of the interim connection limit were successfully allocated, including the execution of two load contracts.

Phase 2: Large Load Working Group Engagement

Pre-engagement for Phase 2 began in September 2025 and industry engagement will continue into early 2026. In Phase 2, the AESO is developing a long-term framework to manage future large-load connections, including for data centres. The engagement process is aimed at designing a scalable approach.

The AESO highlighted three core dependencies that will guide Phase 2 engagement and implementation:

1. alignment with ongoing AESO engagements covering interdependent topics;
2. government legislative schedules, if policy changes are necessary for solutions; and
3. determination of whether solutions require regulatory filings or can proceed through AESO process documentation.

Several key questions are also guiding industry engagement including how the AESO can balance grid reliability while integrating large-load requests, how to ensure large-loads are a benefit to the grid, and how to ensure large-load projects are contributing proportionately to transmission costs. The initial round of pre-engagement is focused on cost-allocation, investment, and cost-of-service. The first large load working group will collaborate regarding the connection process, specifically targeting self-supply, net new generation, and MW allocation frameworks for large load projects. Broader industry engagement will occur in early 2026.

The AESO will continue engaging stakeholders throughout 2026, and intends to finalize AUC applications by Q1 of 2027.

Data-Center Self-Supply and Bill 8

A large part of the conversation surrounding data centers in Alberta is how the AESO will integrate self-supplying large load projects. The emphasis on self-generating data centre projects was highlighted in a mandate letter to the Minister of Technology and Innovation, requesting that “AI data centre proponents with ‘bring your own power’ power generation projects are fast tracked through the required regulatory processes.” On December 11, 2025, the Alberta government passed Bill 8, the Utilities Statutes Amendment Act, 2025. Bill 8 serves to prioritize self-generating data centers and support grid reliability in Alberta. This is part of the major overhaul of Alberta’s electricity market, parallel with the AESO’s long-term framework development and REM implementation (beginning in 2027), as discussed earlier in this chapter.

Fast Frequency Response Plus (FRR+)

On April 10, 2025, the EUA was amended through Section 17.1 to provide that the AESO may procure ancillary services, including entering into arrangements or agreements in accordance with any conditions or limitations prescribed by the regulations, and that in so doing, the AESO must have regard to reliability, technical feasibility, cost effectiveness, the principles of fairness, efficiency, and open competition, and any other factors prescribed by the regulations.

The AESO is engaging on the procurement of highly available FFR to meet the requirements outlined in the amended Transmission Regulation, and the ancillary services provisions in the Energy and Utilities Statutes Amendment Act (Bill 52). Through this engagement, the AESO is seeking input on different product and procurement designs for highly available FFR to support full import flows on the Alberta-British Columbia and Montana-Alberta interties. Currently, the AESO procures FFR through voluntary arrangements that do not guarantee high availability. To meet the new requirements, the AESO is proposing to competitively procure up to 750 MW of highly available FFR+ through commercial contracts. Once the stakeholder engagement process is completed, we anticipate the AESO will launch the FFR+ procurement in 2026.