On April 10, 2025, Alberta Minister of Affordability and Utilities, Hon. Nathan Neudorf (the Minister) tabled Bill 52, Energy and Utilities Statutes Amendment Act, 2025 [PDF] (Bill 52 or the Bill). The Bill proposes a series of amendments to Alberta's Electric Utilities Act, Gas Distribution Act, Gas Utilities Act, Hydrogen and Electric Energy Act, and Petroleum Marketing Act. Chief among the amendments are provisions that would enable the implementation of a restructured energy market and modified electricity transmission planning and management in Alberta, and provisions that permit hydrogen-blended consumer natural gas.
This Update provides an overview of the proposed amendments to the Electric Utilities Act, the Gas Distribution Act and Gas Utilities Act.1
Changes to the energy market and transmission policy
Bill 52 marks one of the first legislative tools proposed by the government of Alberta to implement the Restructured Energy Market (REM) and Optimal Transmission Planning (OTP) policy initiatives. The Bill proposes amendments to the Electric Utilities Act that, among other things, would modify certain Alberta Electric System Operator (AESO) duties with respect to operating the energy market and planning the transmission system, and would enable the Minister to create new regulations and Independent System Operator (ISO) rules to implement the REM. Details of the REM and OTP remain subject to ongoing engagement efforts by the AESO following direction letters from the Minister to the AESO.2 Osler has previously discussed the REM and OTP in our prior Update.
Implementing the restructured energy market
Amendments proposed in Bill 52, if passed, would replace the current real-time power pool with both a day-ahead market and a real-time market, enable administrative and locational pricing mechanisms, impose new duties on the AESO to prioritize cost and manage transmission constraints through the dispatch and price of electricity, and create new powers for the Minister to enact regulations and to legislate ISO rules to implement the REM. The amendments largely reflect the legislative changes proposed by the AESO in its original recommendation report to the Minister in early 2024.3
The amendments provide the legislative changes required to implement the REM through new or amended regulations and ISO rules on an expedited timeline. The government of Alberta has set a target for implementation by 2027.
Notable amendments proposed by Bill 52 include the following:
- Replacing the power pool with a day-ahead market and real-time market: the amendments would enable both a day-ahead market (where electricity and reliability products can be exchanged on a forward-basis) and a real-time market (where electricity and reliability products can be exchanged in real-time, like the existing energy-only market). Although the AESO recently announced a move away from a day-ahead energy market during consultation on the REM,4 the amendments proposed in Bill 52 will facilitate enhancements to the day-ahead reliability market and the development of other day-ahead products. Notably, the proposed definition of "day-ahead market" includes a market for both electric energy and certain ancillary services (section 1(1)(h.1)), which would appear to facilitate day-ahead energy market products if introduced in the future.
The government of Alberta has indicated support for the AESO's decision to abandon the day-ahead energy market and move forward with improvements to the current day-ahead reliability market only.5 The AESO has indicated it is considering changes to the current day-ahead reliability market, including changes to bid and offer size, introducing scarcity pricing, and procuring new reliability products like ramping reserves.6
- Modified AESO duties to manage overall costs and transmission
constraints through price-setting and dispatch. Currently, the AESO
operates the power pool and dispatches electricity according to
relative economic merit pursuant to section 18(1) of the
Electric Utilities Act. The AESO has limited ability to
reconstitute the pool price or dispatch generation outside of the
merit-order established in the power pool. The amendments proposed
by Bill 52 would modify several of the AESO's duties with
respect to dispatch and determining the price of electricity,
enabling the AESO to implement and operationalize the REM,
including:
- rather than dispatching in accordance with relative economic merit, the AESO must dispatch electric energy and ancillary services "in a manner that minimizes the overall cost of dispatching electricity" (section 17(c))
- the AESO must "prioritize, restrict, or vary the dispatch or pricing of electric energy during periods of transmission constraints" (section 17(b.1))
- the AESO must "operate the electricity market in a manner that accounts for transmission constraints" (section 18(2))
- the prices established by the AESO may vary by location (section 18(6))
- the AESO may, in accordance with ISO rules, establish frameworks involving minimum and maximum offer prices (e.g., secondary offer caps, scarcity pricing or negative pricing), processes for reviewing and updating prices, and safeguards to limit the exercise of excess market power and ensure transparency (such as the recently approved ISO rules 206.1 Interim Secondary Offer Cap and 206.2 Interim Supply Cushion Directives) (section 18(7)).
- Settlement intervals: Bill 52 would remove the currently prescribed maximum settlement interval of 60 minutes for financial settlement of transactions and instead delegate the determination of settlement intervals to either the Minister under the REM ISO rules, or the ISO, as the case may be (section 1(1)(xx.1)). The Minister has directed, and the AESO has indicated, that the REM will include a transition to a shorter 5-minute settlement interval.7
- Broader definition and procurement of ancillary services: Bill 52 would expand the definition of ancillary services from those services required to ensure the grid is operated in a manner that "provides satisfactory service with acceptable levels of voltage and frequency," to those services "necessary to support the transmission and supply of electricity while maintaining reliable operation of the interconnected electric system" (section 1(1)(b)). The amendments would also enable the AESO to procure ancillary services out-of-market, subject to the regulations (section 17.1).
- Ministerial powers: as proposed by the AESO in its original recommendation report to the Minister,8 implementing the REM within the target timeframe requires legislation to expedite or remove regulatory review of REM ISO rules by the Commission. The amendments contemplate the Minister enacting ISO rules by regulation with no Commission oversight, including the possibility of the Minister enacting regulations limiting the complaint jurisdiction of the Commission under sections 25 and 26 of the Electric Utilities Act.
The legislative implementation of the REM favours speed and certainty over transparency and technical accuracy,9 and has caused concern for many stakeholders. However, the Minister has indicated that Ministerial REM ISO rules will be interim, and eventually subject to Commission approval.10
The Minister also has new regulation-making authority under the proposed amendments to make regulations for the management of transmission constraints by the AESO (section 41(1)(a.3)) or specifying the ancillary services that may be included in the day-ahead market and real-time market (section 41(1)(a.4)).
Cost allocation
One of the key themes emphasized by the Government of Alberta in its policy directions and announcements on Bill 52 is allocating costs based on cost-causation. Notably, the amendments proposed by Bill 52 include new rule-making authority for the AESO to create ISO rules for the recovery of ancillary services costs (section 20(1)(d)), which would enable the AESO to implement rules allocating ancillary services costs based on cost causation principles.
In his December 10, 2024 direction letter to the AESO, the Minster also directed that the cost allocation framework for new transmission infrastructure be based on cost-causation principles by replacing the Generating Unit Owner's Contribution (GUOC) with an upfront and non-refundable transmission reinforcement payment (TRP). The current GUOC requirements are found in the Transmission Regulation and it is anticipated that amendments to the Transmission Regulation and the ISO Tariff will be forthcoming to enable a TRP.
Removing the zero-congestion policy
If passed, Bill 52 will also lay the foundation for moving away from the current "zero-congestion" transmission planning standard.11 That is, in addition to the market-based mechanisms for managing transmission constraints and optimizing the efficient use of current transmission facilities noted above, the proposed amendments would recognize that
- the AESO's duty to provide a reasonable opportunity to market participants to exchange electric energy and ancillary services does not require the removal of transmission constraints (section 29(2)), nor does it obligate the AESO to plan a transmission system in a manner that removes all transmission constraints or ensures unconstrainted access (section 29(3)
- in planning the transmission system. the AESO "is not obligated to plan for the removal of all transmission constraints" (section 33(1)(a)) and must implement expansions and enhancements in a manner that "maintains system reliability and can reasonably be expected to maximize economic efficiency" (section 33(1)(b))
- the AESO is also enabled to make rules to manage transmission constraints, including rules the prioritize, restrict or vary the dispatch or pricing of electric energy during periods of transmission constraint (section 20(1)(c.1))
The Alberta Market Surveillance Administrator (MSA) has called the zero-congestion standard a "substantial waste of society's resources."12 Moving away from the zero-congestion standard may create risk for generators wishing to deliver electricity to the grid. However, the government has justified the shift on the basis that it will reduce the overall need for new transmission infrastructure, saving consumers from further escalation in transmission costs— one of the government's key transmission policy goals.
Driving innovation in hydrogen
Bill 52 proposes amendments to the Gas Distribution Act and Gas Utilities Act which would allow hydrogen blending in the natural gas distribution system for residential and commercial customers up to a "maximum blending limit" established by regulation under the Gas Utilities Act. Alberta is the largest hydrogen producer in Canada, and the government of Alberta has indicated its intention to position the province as a global leader in the hydrogen economy, including the government's 2021 Hydrogen Roadmap, which highlighted key markets for the growth of hydrogen in Alberta, like residential and commercial gas utility systems.
Under the proposed amendments to the Gas Utilities Act, gas utilities wishing to supply hydrogen-blended natural gas to consumers must obtain the prior approval of the Alberta Utilities Commission (the Commission) (section 48.2) and can only recover the costs of hydrogen-blended natural gas services from consumers who receive it (section 48.3). The Minister also has new regulation-making authority under the Gas Utilities Act, including the ability to exempt pilot projects initiated prior to February 25, 2025 (section 48.4(2)).
The Minister indicated that the government of Alberta is working with regulators, such as the Canadian Standards Association, to set the rate of blending at a safe level.13
Osler will continue to monitor these developments closely. Our firm has extensive experience providing advice to utilities and generators both in Alberta and in jurisdictions across Canada. If you have any questions regarding the implications of these ongoing policy developments, please contact a member of the Osler Regulatory or Energy groups or the authors of this article.
Footnotes
1. Where references to a specific section are shown in brackets below, the reference is to the new or amended section of the subject legislation if Bill 52 were passed in its current form.
2. See direction letter dated July 3, 2024 and direction letter dated December 10, 2024.
3. AESO, "Alberta's Restructured Energy Market – AESO Recommendation to the Minister of Affordability and Utilities" [PDF] 38 and 39 of 139.
4. See AESO AESO REM DFS – Week 3 Presentation (Posted April 10 2025) (1.41 MB) [PDF] 8.
5. Government of Alberta, "Powering prosperity with strong utilities – April 10, 2025" online < https://youtu.be/zizOnPquJhg >, at 7:02; see also Government of Alberta, "Transforming the utilities system".
6. See AESO AESO REM DFS – Week 3 Presentation (Posted April 10 2025) (1.41 MB) [PDF] 8, 11 and 15 of 17.
7. See Ministerial direction letter dated December 10, 2024; see also AESO Restructured Energy Market High‑Level Design (December 13, 2024) [PDF] 48 of 50.
8. AESO, "Alberta's Restructured Energy Market – AESO Recommendation to the Minister of Affordability and Utilities" [PDF] 37-39 of 139.
9. AESO, "Alberta's Restructured Energy Market – AESO Recommendation to the Minister of Affordability and Utilities" [PDF] 72 of 139.
10. Government of Alberta, "Powering prosperity with strong utilities – April 10, 2025" online < https://youtu.be/zizOnPquJhg >, at 11:15.
11. Transmission Regulation, Alta Reg 86/2007, section 15(1)(e).
12. See MSA, Confidential Advice to Executive Council and the Minister of Affordability and Utilities (December 21, 2023), online [PDF]: < https://www.albertamsa.ca/assets/Documents/MSA-Advice-to-Minister.pdf > [PDF] 26 of 51.
13. Government of Alberta, "Powering prosperity with strong utilities – April 10, 2025" online < https://youtu.be/zizOnPquJhg > at 1:30 and 4:07.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.
