Power Perspectives: Alberta Regional Overview

This article originally appeared as a chapter in our Power Perspectives 2025 publication and provides a look back at some of the key developments in the Alberta power market occurring in 2024. Power Perspectives 2025 provides an in-depth overview of the most significant developments in the Canadian power and emerging energy sectors in 2025.

Since December 2024, the regulatory and policy landscape in Alberta and Canada continues to evolve, including a recent Federal Election and the formation of a new Liberal minority government (see our recent update on the Liberal Party's Energy Platform). In Alberta, 2025 brings the anticipation of significant increases in power demand (up to 11 MW) from proposed new data centres, proposed changes to the Alberta Utilities Commission's ("AUC") Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations, Hydro Developments and Gas Utility Pipelines and further changes and further announcements pertaining to the Restructured Energy Market (the "REM"). Our most recent insights on new developments on REM can be found in our April 16, 2025 update.

In support of REM and the Province's goals of modernizing and increasing the reliability and affordability of our utility systems, Alberta introduced Bill 52, the Energy and Utilities Statutes Amendment Act ("Bill 52") on April 10, 2025, proposing amendments to several statutes, including the Electric Utilities Act and the creation of a Day-Ahead Market for trading electricity and ancillary services and a Real-Time Market for electricity transactions. You can expect to see a blog from our National Energy Group in the near future with our insights on the more significant impacts of Bill 52.

As always, our National Energy Group continues to monitor new developments in Alberta and throughout Canada and recent insights can be found on our Canadian Energy Perspectives blog.

Introduction

2024 was another busy year in Alberta with energy industry support and electricity market reform as key drivers in changes to our policy and regulatory landscape. Following the regulatory pause on renewables and the Government of Alberta's (the "Province") stated intention of continuing to challenge federal initiatives on emissions reductions, we see continued support for a strong oil and gas industry and conventional generation, mixed with energy diversification initiatives.

Alberta is facing a major electricity market overhaul through the REM with a focus on providing stable, reliable and affordable energy generation. While the REM takes shape, there is a level of uncertainty in the market that stakeholders are attempting to navigate as they consider project development and acquisition opportunities.

And let us not forget our energy transition initiatives, with the execution of the first Carbon Sequestration Lease Agreements for carbon sequestration hubs in the Province, among numerous other project announcements and developments in our emerging energy sectors. 2025 is bound to be another exciting year in the energy sector in Alberta, as we balance competing goals and initiatives in driving towards a sustainable energy future.

Market Update

Regulatory Pause on Renewables

In August of 2023, the Province issued an order-in-council¹ pursuant to which the Alberta Utilities Commission ("AUC") was ordered to inquire into and report to the Minister of Affordability and Utilities ("MUA") on the ongoing economic, orderly and efficient development and operation of electricity generation in Alberta. The Province further issued a second order-in-council² enacting the Generation Approvals Pause Regulation³ which restrained the AUC from granting approvals with respect to any hydro development or power plant that produces renewable electricity until February 29, 2024, subject to certain exceptions (the "Renewables Pause"). On February 28, 2024, the Province lifted the Renewables Pause and, further to the AUC's Module A Inquiry and resulting report, announced policy guidance ("Policy Guidance") regarding its intention to advance what it deemed necessary policy, legislative and regulatory changes to the renewables regime in Alberta. The Policy Guidance was further supplemented by the announcement of the new Electric Energy Land Use and Visual Assessment Regulation⁴ ("Land Use and Assessment Regulation") as well as amendments to the Activities Designation Regulation⁵ ("Activities Regulation") and the Conservation and Reclamation Regulation⁶ ("Conservation Regulation"), all of which can be summarized as follows.

• Agricultural Lands. The AUC was directed to take an "agriculture first" approach when evaluating proposals for renewable development, ensuring that Alberta's native grasslands, irrigable and productive lands will continue to be available for agricultural production and not impacted by future renewable electricity generation projects. In support of this approach, the Province will no longer permit renewable generation developments on Class 1 and Class 2 lands, as classified by the Alberta Land Suitability Rating System,⁷ unless a proponent can demonstrate the ability for both crops and/or livestock and renewable generation to co-exist. An irrigability assessment ("Irrigability Assessment") must be conducted by proponents and considered by the AUC. Under the Land Use Regulation, a proponent applying for the construction or operation of a Power Plant within the "White Area"⁸ may be required to submit an Irrigability Assessment by the AUC.
• Reclamation Security. The Policy Guidance announced that the Province would implement the necessary policies and tools to ensure that for approvals issued on or after March 1, 2024, developers are responsible for end-of-life reclamation costs, and must post bonds or security to the Province in an amount determined by the Province. Pursuant to the amendments to the Activities Regulation and Conservation Regulation, consistent reclamation requirements are required across all forms of renewable energy operations. This includes mandatory reclamation security requirements as well as a mandatory security requirement for projects located on private lands. Through a mandatory security or bond, the developers of renewable projects will be responsible for reclamation costs. Such reclamation security will be provided directly to the province or may be negotiated with landowners where sufficient evidence has been provided to the AUC.
• Protected Areas. Pursuant to the Land Use and Assessment Regulation, "pristine viewscapes" are conserved through the establishment of buffer zones where new wind projects will no longer be permitted. Other developments proposed within the buffer zones could trigger the need for a visual impact assessment to be provided to the appropriate regulator for consideration. Any electricity development that is proposed within a visual impact assessment zone, as designated by the Province, will be required to submit a visual impact assessment prior to approval.
• Crown Lands. The Province will enable the development of renewable generation on Crown lands on a case-by-case basis. The Province intends to engage with stakeholders, including any impacted Indigenous parties, in a meaningful consultation process, to develop a policy framework for renewable generation on Crown land. Any resulting legislative changes are expected in late 2025.
• The AUC is in the process of implementing rule changes which would: (i) automatically grant municipalities the right to participate in AUC hearings; (ii) enable municipalities to be eligible to request cost recovery for participation and review; and (iii) permit municipalities the right to review rules related to municipal submission requirements while clarifying consultation requirements.

Update on Carbon Capture, Storage and Utilization ("CCUS")

In the summer of 2024, the first Sequestration Lease Agreement ("SLA") for CO₂ storage pursuant to the Province's competitive bid process for carbon storage hubs was signed among the Province, Shell and ATCO EnPower for the Atlas carbon storage hub. This was hailed as a historic agreement for CCUS development in Alberta and ultimately led to the release by the Province of the standard form SLA that other hub proponents will be required to sign as they advance their projects in Alberta.⁹

While the Province continues down the path of encouraging the development of large-scale CCUS hubs, near the end of 2023 the Province released the application guidelines for Small-Scale and Remote Carbon Sequestration Tenure,¹⁰ allowing CCUS projects outside of the hub model to the extent they meet the specified criteria, including that the requested lands cannot overlap with existing carbon sequestration agreements or grants of pore space (including areas of interest for hub proponents and conventional subsurface reservoir leases). Applicants must make the business case for why they need the carbon sequestration operation, describing the source of emissions and projected timeline for the project and providing a rationale for why sequestration in a proposed hub is not viable (timeline, economics, distance etc.).

Update on Carbon Capture Incentive Program

The Alberta Carbon Capture Incentive Program (the "ACCIP") was further detailed by the Province in April 2024 and aims to support and accelerate the development of CCUS infrastructure. The ACCIP plays a critical role in Alberta's strategy to remain at the forefront of CCUS development and environmental sustainability.

The ACCIP offers a 12% grant on new eligible CCUS capital costs. The grant is paid in three installments over three years, starting after the first year of operations. Importantly, the ACCIP will cover projects in various sectors, such as oil sands, oil and gas production, enhanced oil recovery, petrochemicals, power generation, manufacturing, and cement production.

The ACCIP is designed to complement federal incentives, particularly the federal CCUS Investment Tax Credit ("CCUS ITC"), which provides significant tax benefits for companies investing in CCUS technologies. Although the ACCIP will largely align with the CCUS ITC, it allows for some flexibility where the federal tax credit does not apply. For example, the ACCIP will support projects that result in the permanent sequestration of carbon dioxide ("CO₂"), which includes enhanced oil recovery production, which is explicitly an "ineligible use" under the CCUS ITC.

Eligible projects must be located in Alberta and focus on capturing, compressing, storing, or utilizing CO₂. These projects are retroactively eligible for costs incurred from January 1, 2022, in alignment with the CCUS ITC. However, projects that have received funding through Alberta's Petrochemical Incentives Program or other royalty regimes cannot claim duplicate benefits for the same expenses.

The ACCIP will be funded by Alberta's Technology Innovation and Emissions Reduction Fund, which is fuelled by companies purchasing carbon credits to meet emission targets. The total funding is expected to be between C$3.2 billion and C$5.3 billion through 2035.

Key Developments in 2024

Developments in Alberta's Restructured Energy Market

Background

On August 2, 2023, the Province issued an order-in council¹¹ pursuant to which the AUC was ordered to inquire into and report to the MUA on the ongoing economic, orderly and efficient development and operation of electricity generation in Alberta.

On March 11, 2024, the MUA directed the AESO to commence drafting a technical design proposal for the REM. This directive was influenced by recommendations from the respective reports of the AESO¹² and the Market Surveillance Administrator ("MSA").¹³ The AESO report revealed its preliminary plan for the REM and the chosen strategy designed to improve system reliability and affordability.

On July 3, 2024, the MUA issued a direction letter to the AESO regarding the government's policy decisions for advancing the design of the REM. Specifically, the AESO was directed to proceed with:

• the introduction of a mandatory day-ahead market;
• allowing the price of energy to be determined by the strategic offers of market participants, while using market mitigation to limit the potential for excessive exercise of market power;
• maintaining a province-wide uniform price for electricity; and
• maintaining the following components of the REM as outlined in the AESO's confidential advice to the MUA: "Security Constrained Economic Dispatch" shorter settlement intervals, a review of the price floor and ceiling as well as the co-optimization of energy and ancillary services.

The confirmation from the MUA regarding the policy direction for the design enabled the AESO to concentrate on the detailed aspects of the design, ensuring the development of a workable market.

The AESO strategically divided the REM into six focused workstreams to facilitate the development process: (1) Day-Ahead Market, (2) Pricing and Energy Reserve Market, (3) Intertie Participation, (4) Market Power Mitigation, (5) Dispatch Optimization, and (6) Shorter Settlements. For each workstream, the AESO released a detailed options paper. Each paper provided a number of options for each workstream within the guardrails of the Province's direction, which served as a starting point for consultation in the design sprints.

Design Sprints

Between September 10 and November 28, 2024, the AESO conducted a series of six intensive design sprints, spanning a total of 24 days and encompassing approximately 200 hours of stakeholder consultation. These interactive sessions were facilitated both in-person and virtually, ensuring broad accessibility and participation. The workshops included comprehensive presentations from the AESO about design aspects, alongside analyses from third-party consultants. The sprints were structured to facilitate a continuous exchange of dialogue and to solicit ongoing feedback from participants.

Outcomes on the Workstreams

Following the first six REM Design Sprints, the AESO released the High-Level Design covering each element of the market design, incorporating stakeholder feedback from the design sprints. Stakeholder feedback on the High-Level Design can be provided to the AESO until January 27, 2025. As discussed in detail within the High-Level Design, the six key elements of the REM design are:

• New Day-Ahead Markets: Financial day-ahead market and physical day-ahead commitment (DAC) helps price discovery and meets reliability needs.
• New Reserve Products: New products support reliability attributes markets to balance real-time supply and demand.
• Dispatch to Manage Reliability: Better tools needs to manage increasingly complex system.
• Wide Price Range and Scarcity Pricing: Better values reliability attributes when needed most, without relying on large participant actions.
• Co-optimization: Minimizes operating reserve costs by allowing for one product to fulfill requirements for another.
• Market Power Mitigation: Ensures affordable outcomes for consumers by implementing safeguards against excessive market power.

Additional Direction from the MAU and Implementation of REM

Additional direction from the MAU associated with the REM Market Design was provided on December 10, 2024. Within this Letter, the MAU directed the AESO to continue the REM technical design as outline in the July 3, 2024 Direction Letter subject to the following further decisions, the AESO will:

• Develop a market-based congestion management mechanism that recognizes incumbency, provides impacted generators with a means of managing the dispatch risk arising from congestion constraints, and considers the participation of controllable load and energy storage. Any revenue generated from this mechanism will be applied toward the cost of transmission projects prioritizing congested areas of the province.
• Continue to have robust engagement with stakeholders on the development of the Independent System Operator ("ISO") Rules that will implement the REM, while ensuring alignment with the Province's objectives of reliability, affordability, investability, economic efficiency, and sustainability.
• Develop an energy pricing framework in accordance with guidance that will be provided within legislation.
• Collaborate with an AUC-led initiative to implement 5-minute settlement for transmission-connected loads, generators and interties by 2032 and for all loads by 2040.

The Province is directing the AESO to continue developing the detailed design of the REM in consultation with stakeholders, with a view to finalizing the detailed REM design before the end of 2025. For the implementation of REM, the Province indicated it will bring forward necessary policy tools to allow the initial set of ISO Rules required for REM to be enacted via legislation. Under this approach, the initial REM rules will be enacted but not brought into effect before the end of 2025. The AESO will continue to work with stakeholders to develop an implementation plan to consider overall industry readiness for the market transition.

With implementation of the REM rules and the AESO new market systems infrastructure, an interim period will commence. It is intended that during this interim period, a mechanism will be provided for the AESO to correct possible technical deficiencies with the REM rules in an expeditious manner. The new market would then operated for a period of time before the interim period comes to an end.

At the end of the interim period and beyond, any proposed amendments to the REM rules will require AUC approval in accordance with established process for ISO Rules.

Update on Transmission Policy Review

Further to the reforms outlined in the Province's July 3, 2024 direction letter, the Province, in a further direction letter issued on December 10, 2024, announced additional guidance to the AESO's responsibilities for planning the transmission system and developing the ISO tariff. The guidance includes the following:

• Implement a cost allocation framework for new transmission infrastructure based on cost-causation principles by requiring new generators to contribute to transmission infrastructure costs by replacing the Generating Unit Owner's Contribution with an upfront non-refundable Transmission Reinforcement Payment ("TRP").
  • These payments will have a floor of $0/megawatt and no upper limit and are intended to apply to both transmission-connected and distribution-connected generators.
  • TRP rates will be calculated as a function of the suppliers' proximity to the transmission capacity, their technical attributes and characteristics, and the cost of reinforcing the transmission system.
• Recover line losses through a system-wide average starting on January 1, 2027.
• The AESO will be required to do the following:
  • file a needs identification document for the Alberta Intertie Restoration Project by December 31, 2026, to restore the Alberta-British Columbia intertie to or near to 950 megawatts;
  • procure and maintain high levels of ancillary services to support full import flows on the Alberta-British Columbia intertie and the Montana Alberta Tie Line;
  • increase the path rating of the Alberta-Saskatchewan Intertie as part of the McNeill Converter's end-of-life replacement to leverage the existing transmission capacity in the region; and
  • remove the competitive procurement requirement for upgrades or enhancements to the path rating of interties.

In order to implement other transmission policy changes, with a view to expeditious implementation, the Province also directed the AESO to commence stakeholder consultation.

Bill 18 (Provincial Priorities Act)

On April 10, 2024, the Province introduced Bill 18, known as the Provincial Priorities Act¹⁴ ("Priorities Act"), with the stated goal of ensuring that agreements made with the federal government align with the Province's strategic goals and financial commitments at all times.

The Priorities Act received royal assent on May 30, 2024, and is anticipated to come into force in early 2025, once the regulations are finalized. Currently, the detailed procedures for obtaining the requisite provincial approval and any exemptions are unknown. The Priorities Act will apply to intergovernmental agreements entered into by "provincial entities" (e.g., municipalities, public post-secondary institutions and Crown-controlled organizations) but will not apply retroactively to existing agreements or projects. However, it appears that the Priorities Act will apply to any amendments, extensions and renewals of these pre-existing agreements. Going forward, prior to initiating, amending, extending, or renewing any intergovernmental agreement with federal government entities, "provincial entities" will need to secure advance approval from the Province. Failure to obtain such Provincial approval purports to have the effect of deeming the subject agreement invalid and of no force and effect.

Altius Royalty Corporation v. Alberta

On April 4, 2024, the Alberta Court of Appeal (the "Court") released a judgment in Altius Royalty Corporation v. Alberta¹⁵ ("Altius"), clarifying how constructive expropriation applies to the Province's plan to phase out coal-fired electricity generation emissions by 2030. Altius Royalty Corporation, Genesee Royalty Limited Partnership and Genesee Royalty GP Inc. (collectively, the "Appellants") held royalty interests in the Genesee coal mine, which fuels the Genesee power plant that provides energy to the City of Edmonton. The Government of Canada and the Province (the "Respondents"), respectively, introduced legislation to phase out coal-fired electrical generation and entered into off-coal agreements ("Off-Coal Agreements") with owners of coal-fired power plants to end this type of higher emissions generation. The Appellants argued that the Respondent's legislation and Off-Coal Agreements amounted to constructive expropriation since it precluded their ability to receive royalties from their interest in the mine post-2030. The test for constructive appropriation requiring compensation, requires: (1) an acquisition of a beneficial interest in the property or flowing from it (an "advantage"); and (2) removal of all reasonable uses of the property.

The Court concluded that for constructive expropriation to occur, the interest allegedly being expropriated must be sufficiently proprietary such that it can be acquired, and that there must be some correspondence between the expropriated interests and the acquired interest. The Appellants argued that the advantage flowing to the Respondents is a reduction in healthcare and environmental expenses, and that since a dollar amount can be attributed to these expenses, the advantage is proprietary. The Court ruled that a generalized public benefit cannot constitute an advantage flowing to the Crown in satisfaction of the constructive expropriation test. As a result, the Court did not consider the second step of the test.

The Government of Canada's public policy goal behind the regulation of coal-fired electricity generation was not an advantage regarding private property accruing to the Crown. Further, the loss of royalties sustained by the Appellants was a result of the owners of coal-fired generation plants' decision to cease operations in light of their private Off-Coal Agreements with the Province, not constructive expropriation.

In conclusion, the Court clarified that it will not expand the interpretation of the constructive expropriation test to include situations where regulations impact royalty interests in the Province's energy sector. The decision in Altius suggests that the parties alleging constructive expropriation of coal royalties in response to anti-coal legislation or Off-Coal Agreements may face judicial resistance.

Regulatory Updates

AUC Rule 007 Updates

Updates to AUC application review process following Renewables Pause

As previously noted, the Renewables Pause, which prevented the AUC from issuing approvals for new power plants and hydro developments producing renewable electricity over 1 megawatt, expired on February 29, 2024. Since March 1, 2024, the AUC resumed issuing decisions on affected power plant applications.

Enhanced interim information requirements

In September 2023, the AUC introduced interim information requirements for new power plant applications (wind, solar, thermal, hydroelectric, and others), covering agricultural land, viewscapes, reclamation security and municipal land use. Based on stakeholder feedback and guidance from the Province, the AUC will continue using these requirements, with the following additional details on reclamation security:

1. A third-party report estimating reclamation costs, including the salvage value of project components; and
2. An explanation of the chosen form of security, its attributes, and how the secured party can realize on the security if the project defaults.

New power plant and energy storage facility applications filed after May 2, 2024, must meet both the existing requirements of Rule 007 and these enhanced interim requirements. Moving forward, it is important to note that the rules are still being finalized, and ongoing public consultations will shape the final outcomes. The interim information requirements are in effect until further notice.

Additional amendments came into force on March 28, 2024, clarifying requirements involving the lifespan of energy storage facilities and exemptions from filing applications for small power plants, small energy storage facilities and isolated generating units, as follows:

• Energy Storage Facility: Information required for amending, decommissioning and salvaging, cancelling or extending the construction completion date of an energy storage facility has been added in a separate section.
• Exemptions from Filing Applications: Owners of small power plants, small energy storage facilities, and isolated generating units are exempt from filing an AUC application if the construction or operation of small power plants, small energy storage facilities and isolated generating units: (i) does not directly and adversely affect any person; (ii) does not have an adverse environmental impact; and (iii) meets the requirements of AUC Rule 012: Noise Control.

Land Use and Assessment Regulation

As further discussed in the Environmental Law chapter of the full Power Perspectives publication, the Land Use and Visual Assessment Regulation generally applies to applications for the construction or operation of Power Plants¹⁶ under Rule 007, provided however the Land Use and Assessment Regulation does not apply to the following: (a) the construction or operation of (i) small Power Plants, (ii) isolated generating units, and (iii) micro-generation generating units; (b) the construction or operation of a Power Plant situated on a reserve; and (c) alterations to an existing Power Plant approval issued by the AUC.

The Land Use and Visual Assessment Regulation imposes obligations on proponents to three broad areas for renewable energy developments:

• Agricultural Land Use: Proponents applying for construction or operation of a wind plant or solar power plant on privately owned "high-quality agricultural land" will be required to submit an "agricultural impact assessment" as part of their application detailing the effects of the plant on agricultural productivity and that includes measures demonstrating that the plant is designed to "coexist" with agricultural operations and land use, including both crops and/or livestock.
• Irrigability Assessment: Proponents applying for construction or operation of a Power Plant within the "White Area" may be required to submit an Irrigability Assessment to the AUC, which may include: (a) an evaluation of water quality and availability; (b) an analysis of proximity to irrigation infrastructure; (c) the economic viability or feasibility of irrigation; and (d) the opinions of the applicable irrigation district.
• Buffer Zones and Visual Impact Assessment Zones: To ensure that "pristine viewscapes" are conserved, the AUC will no longer accept any applications under Rule 007 for the construction or operation of a wind power plant in a buffer zone, as described in a schedule to the Land Use and Assessment Regulation. A proponent applying for construction or operation of a Power Plant within a buffer zone must submit a "visual impact assessment" which may include: (a) an evaluation of the anticipated visual impacts on the buffer zone; (b) visual simulations from key vantage points illustrating the potential visual impact on the proposed Power Plant; and (c) proposed mitigation measures to minimize or offset any adverse visual effects on the buffer zone.

The Land Use and Visual Assessment Regulation is set to expire on December 31, 2029, as a measure to ensure that it is reviewed for ongoing relevancy and necessity.

Conservation and Reclamation Amendment Regulation

The Amended Reclamation Regulation, enacted under the Environmental Protection and Enhancement Act(EPEA), revises the existing Conservation and Reclamation Regulation. The Amended Reclamation Regulation updates the existing regulatory framework for wind and solar power plants:

1. New Code: The Amended Reclamation Regulation introduces the Code of Practice for Solar and Wind Renewable Energy Operations (the Code). Those carrying on the construction, operation or reclamation of a "solar electric renewable energy operation" or "wind electric renewable energy operation" (the "Specified Activities") are required to comply with the Code.
   
   The Code will apply if (i) the total footprint of the operation is greater than one hectare, or (ii) the amount of electricity generated from the operation is greater than the maximum amount permitted for a large micro-generation as specified in the Micro-generation Regulation, but does not include an operation that is operated by a person solely on property of which that person is the owner, for use solely by that person and solely on that property.
   
   
2. Imposing Security Obligations: An operator must provide security with respect to a registration for a Specified Activity, prior to the registration being issued. The exact requirements for the type, timing, and amount of the security, according to the Code, have not been made public yet. However, the security provided must comply with the acceptable forms outlined in the Conservation and Reclamation Regulation. These forms include cash, cheque, government bond, an irrevocable letter of credit, a performance bond, or any other form that the Director approves.
   
   
3. Exemption from Security Obligations: An operator is exempt from security obligations if it applies for registration of the Specified Activity under EPEA and provides security to a registered owner of the land under a surface lease.

The Amended Reclamation Regulation states that proponents who were already engaged in the construction, operation, or reclamation of a solar or wind renewable energy operation prior to the amendments taking effect on January 1, 2025, are permitted to continue these activities without obtaining a registration for that activity under the EPEA until January 1, 2027.

Amendments to the Hydro and Electric Energy Act

TheElectricity Statutes (Modernizing Alberta's Electricity Grid) Amendment Act¹⁷ ("ESAA"), originally Bill 22, was proclaimed in March 2024 after nearly two years of regulatory development. The ESAA amends key legislation, such as the Alberta Utilities Commission Act,¹⁸ the Electric Utilities Act¹⁹ and the Hydro and Electric Energy Act.²⁰ These changes are significant as they facilitate the integration of new technologies, including energy storage, and modernize Alberta's electricity infrastructure. Key changes under the ESAA include:

1. energy storage integration;
2. enhanced transmission and distribution planning;
3. clarification on self-supply and export; and
4. winding down of the Balancing Pool.

The ESAA represents a significant advancement in the Province's approach to integrating energy storage into its power grid. Before the ESAA, there was uncertainty about how these facilities would be regulated. By formalizing the application process, the ESAA addresses a longstanding regulatory gap that left energy storage facilities in a gray area between generation and transmission services. Now, investors and developers can proceed with greater confidence knowing that there are clear pathways for energy storage, encouraging innovation and expansion in this sector.

The ESAA's provisions allowing the AESO to procure "non-wires services," including energy storage solutions, is a shift that enhances the flexibility and cost-effectiveness of Alberta's energy grid. By enabling the AESO to use energy storage and other non-wires alternatives under Section 25.1, the ESAA provides a broader toolkit for managing grid demand and alleviating transmission constraints without defaulting to costly new infrastructure investments.

The ESAA's provisions on self-supply and the export of excess electricity mark a critical step toward supporting industrial generators across Alberta. Previously, regulatory ambiguity created significant barriers for industries looking to generate their own power, especially if they wished to sell any surplus back to the grid. The ESAA clarifies these parameters, setting specific conditions under which generators can self-supply and export excess power, opening up new operational and financial opportunities across diverse sectors.

The ESAA's winding down of the Balancing Pool marks the end of an era for Alberta's electricity market. Established to manage Power Purchase Arrangements ("Arrangements") and stabilize the market following the deregulation of electricity in Alberta, the Balancing Pool's primary role was to hold and manage any unclaimed Arrangements, handle associated risks, and manage surplus funds for consumer benefit. However, with the expiration of these Arrangements in 2020, the Balancing Pool's core responsibilities effectively became redundant, prompting the move toward its closure by January 2025. This transition is part of Alberta's broader strategy to streamline the regulatory and operational structures in its electricity market.

Ultimately, the ESAA's clear regulatory framework is anticipated to foster a robust energy storage market in Alberta. This will enhance grid efficiency, reduce costs, and support the Province's shift towards a more sustainable and resilient energy future.

Follow-up on AUC Decision 27084-D02-2023

On October 9, 2023, the AUC released Decision 27084-D02-2023,²¹ adopting a formula-based approach to establish the rate of return on equity ("ROE") for Alberta's regulated electric and natural gas utilities for 2024 and beyond. The AUC also established deemed equity ratios, defining the debt-to-equity ratios for these utilities' capital structures. Together, these factors influence the profitability of each regulated utility.

The deemed equity ratio was determined to be 37% for all distribution and transmission utilities, except for Apex Utilities, which received a ratio of 39%.

This approach, known as the generic cost of capital ("GCOC"), applies to all regulated electric and natural gas utilities, aiming to reduce regulatory lag, and create a more efficient, predictable and cost-effective regulatory process.

The AUC formula will use an equity risk premium approach by incorporating 30-year Government of Canada bond yields and utility bond yield spread. The ROE for 2024 was calculated by the AUC to be 9.28% for all utilities.

The AUC will conduct a mandatory review of cost-of-capital parameters every five years, subject to mid-term reopeners either at its own discretion or upon application from interested parties. The established cost-of-capital parameters apply to:

• AltaLink Management Ltd.
• Apex Utilities Inc.
• ATCO Electric Ltd.
• ATCO Gas and Pipelines Ltd.
• ENMAX Power Corporation
• EPCOR Distribution & Transmission Inc.
• Fortis Alberta Inc.
• Kainai Link L.P.
• City of Lethbridge
• PiikaniLink L.P.
• The City of Red Deer
• TransAlta Corporation

The cost-of-capital parameters for the various investor-owned water utilities under the AUC's jurisdiction were not determined in this proceeding. However, the determinations in this proceeding may be considered in other proceedings should issues respecting ROE and deemed equity ratios arise for these utilities.

What's Next?

In recent years, the regulatory framework governing Alberta's energy market has undergone significant modification, re-evaluation and advancement with the Province mandating a number of reviews of the existing market, regulatory environment and energy infrastructure, and this trend is expected to continue into 2025. In particular, as the REM review nears its conclusion, it is anticipated that this review will prompt a further series of regulatory reform and industry changes in Alberta and that the REM's influence will also extend to the construction and development of expanded infrastructure to support the shift in the energy market.

We anticipate 2025 will bring substantial investment in Alberta's infrastructure with the aim of bolstering the energy sector and the reliability of Alberta's electricity grid. These investments are likely to include construction of new pipelines, an evaluation of Alberta's existing transmission lines and the implementation of advanced energy distribution and storage networks. This includes an assessment and modernization of Alberta's existing intertie system, which plays a crucial role in connecting Alberta's electricity network with neighbouring regions. Investment in Alberta's infrastructure will be necessary to meet the Province's current energy demands, but also to prepare the grid to handle future demand and reliability challenges, including the continued integration of renewable energy sources and evolving consumption patterns.

Special thanks to the following students who helped with this publication: Rahul Bhutani, Amanda Cha, Tyson Jackson, Chiedza Mutize, Mackenzie Oshanek-Gladue, Conrad Parken, Stephan Possin

Footnotes

1. Order-in-council (171/2023).

2. Order-in-council (172/2023).

3. Alta Reg 108/2023.

4. Alta Reg 203/2024.

5. Alta Reg 276/2003.

6. Order-in-council (369/2024).

7. Class 1 lands are those that have none to slight limitations to growth while Class 2 lands are those with slight limitations to growth. It is noted that Alberta has no Class 1 lands.

8. The "White Area" is the part of Alberta shown outlined and colored white on the map annexed to Ministerial Order 71/85.

9. It is noted that since the Shell/ATCO EnPower SLA has been signed, additional hub proponents who were approved by the Province have entered into SLAs.

10 Alberta, Small-scale and remote carbon sequestration tenure: Application guidelines, September 12, 2023, online.

11 Order-in-council (171/2023).

12 Alberta's Restructured Energy Market, AESO Recommendation to the Minister of Affordability and Utilities, January 31, 2024, online (AESO's Advice to the Minister).

13 Advice to support more effective competition in the electricity market: Interim action and an Enhanced Energy Market for Alberta, December 21, 2023, online.

14 SA 2024, c P-35.5.

15 2024 ABCA 105.

16 Pursuant to the Land Use and Visual Assessment Regulation, a "Power Plant" is defined as the facilities for generating and gathering electric energy from any source.

17 2022, SA 2022, c 8.

18 SA 2007, c A-37.2.

19 SA 2003, c E-5.1.

20 RSA 2000, c H-16.

21 AUC Decision 27084-D02-2023, Determination of the Cost-of-Capital Parameters in 2024 and Beyond (October 9, 2023).