Filtered-Insights

FSRA’s new Operational Risk and Resilience Guidance for Ontario insurers

Thu, 09 Jul 2026 00:00:00 Z

On June 8, 2026, the Financial Services Regulatory Authority of Ontario (FSRA) issued its Operational Risk and Resilience Guidance (PC0050APP) for Ontario-incorporated insurance companies and reciprocal insurance exchanges (collectively, Ontario insurers).

The guidance, which sits under FSRA’s Risk-Based Supervisory Framework (RBSF-I), marks an escalation in supervisory focus on cyber threats, data vulnerabilities, third-party dependencies, and climate exposure.

While adoption of the guidance’s principles is not mandatory, FSRA has indicated that an insurer’s adoption of those principles when determining its supervisory approach may be weighed. Ontario insurers should thus treat this guidance as a strong signal of regulatory expectations and an early prompt to assess gaps.

What Ontario insurers should do now

Ontario insurers should consider a structured gap assessment against PC0050APP’s four principles, prioritizing:

Reviewing Board and Senior Management governance structures, including risk appetite documentation and ORMF approval records;
Auditing IT and cybersecurity controls against GR0016INT and confirming incident notification procedures align with FSRA’s materiality thresholds;
Reviewing third-party vendor contracts for notification obligations, audit rights, and BCP/DRP integration;
Testing BCP and DRP adequacy, including scenario-specific stress testing; and
Beginning to incorporate ESG and climate risk considerations into corporate strategy ahead of anticipated further FSRA guidance.

Background

FSRA supervises both Ontario-incorporated insurers and reciprocal exchanges licensed under the Insurance Act (Ontario); PC0050APP supplements the existing Corporate Governance Guidance (PC0051INT) and FSRA’s IT Risk Management Guidance (GR0016INT). However, while GR0016INT applies to all FSRA-regulated entities, including federally incorporated insurers licensed in Ontario, PC0050APP applies to Ontario-incorporated insurers only.

Insurers subject to federal oversight should also note that FSRA’s guidance broadly aligns, but remains separate as provincial guidance, with expectations in force for federally regulated financial institutions under OSFI’s Guideline B-13 – Technology and Cyber Risk Management, reinforcing that operational and cyber resilience is now a pan-Canadian regulatory priority. Ultimately, both FSRA and OSFI have increased their supervisory focus on operational and cyber resilience, resulting in enhanced oversight expectations for insurers operating in Ontario.

PC0050APP’s four principles

PC0050APP is organized around four principles that outline FSRA's intended supervisory outcomes:

(1) Governance

Ultimate accountability for operational risk oversight rests with the Board and Senior Management. FSRA expects Ontario insurers to maintain an Operational Risk Management Framework (ORMF), adopt a three-lines-of-defence structure, and clearly define risk appetite, tolerance, and limits. The Board must periodically review and approve Business Continuity Plans (BCPs) and Disaster Recovery Plans (DRPs).

(2) Risk identification and assessment

Ontario insurers must regularly scan their operating environment, including products, people, processes, systems, and the external environment, to identify and assess inherent operational risks. Information technology is specifically flagged as a significant activity subject to this scan.

(3) Risk management

An effective ORMF should reduce both the frequency and impact of operational risk events. Frameworks and supporting policies must be commensurate with the Ontario insurer’s size, complexity, and risk profile, and integrated with enterprise-wide risk management.

(4) Resilience

Ontario insurers must plan for adverse scenarios and demonstrate crisis readiness. BCPs and DRPs must be tested against severe but plausible scenarios, kept current, and produced for FSRA on request during supervision. The guidance also emphasizes learning from past failures as a driver of continuous improvement.

Four sub-risk categories under the lens

FSRA identifies four sub-risks within its definition of operational risk, each with specific supervisory implications:

(1) Third-party risk

As insurers increasingly rely on cloud service providers and other outsourced vendors, FSRA emphasizes that accountability and ownership of all risks remain with the insurer, regardless of the outsourcing arrangements. Ontario insurers should establish a third-party risk management framework, conduct ongoing due diligence, and ensure contracts contain appropriate notification, audits, and performance provisions. Concentration risk (that is, over-reliance on a single dominant provider) warrants specific attention.

(2) Cyber risk

FSRA will assess IT controls across access management, network security, asset classification and disposal, incident monitoring, and cybersecurity awareness training. Insurers must provide FSRA with timely notification of material IT incidents as required under GR0016INT, which sets a 72-hour notification window for Ontario-incorporated insurers and reciprocals. BCPs and DRPs should specifically address technology service disruptions.

(3) Data risk

Inadequate data governance is a distinct operational risk, spanning integrity, availability, and the safeguarding of confidential consumer information. FSRA will evaluate whether clear accountability and governance frameworks are in place, and whether data capabilities hold up under stress.

(4) Climate risk (physical and transition)

Physical climate events can disrupt critical operations and amplify underwriting losses through increased property damage claims. FSRA currently assesses ESG and climate initiatives as part of the Resilience Rating under RBSF-I, and has signalled that further climate-specific guidance may follow.

The broader regulatory and legal landscape

FSRA’s PC0050APP emerges amid a broader wave of cybersecurity and operational resilience regulation at both federal and provincial levels.

At the federal level, Bill C-8 received Royal Assent on June 15, 2026, thereby completing the legislative process for the Critical Cyber Systems Protection Act (CCSPA) and establishing Canada's first mandatory cybersecurity regime for designated operators in sectors, including telecommunications, banking, and clearing systems. Its provisions will come into force gradually, on a day or days to be fixed by order of the Governor-in-Council; read BLG’s in-depth Insight on the topic, Critical Cyber Systems Protection Act: Bill C-8 is adopted.

While in its current form the CCSPA does not capture federally regulated insurers, insurers that rely on vendors that are designated operators, such as large bank-affiliated cloud providers, may face downstream contractual cybersecurity requirements as those vendors implement their own CCSPA obligations.

Provincially, Ontario's Enhancing Digital Security and Trust Act, 2024 (EDSTA) and its accompanying regulations, O. Reg. 51/26 (Cyber Security) and O. Reg. 52/26 (Digital Technology Affecting Individuals Under Age 18), both in force as of July 1, 2026, impose mandatory cybersecurity programs, biennial cyber maturity assessments, and 72-hour critical incident reporting on prescribed broader public sector entities.

Ontario's Plan to Protect Ontario Act (Budget Measures), 2026 (Bill 97) further modernizes the province's access-to-information and privacy framework by extending privacy impact assessment, breach reporting, and cybersecurity safeguard requirements to municipalities.

Although private insurers are not captured by EDSTA, its regulations, or Bill 97, insurers serving public-sector clients may encounter more rigorous cybersecurity expectations as those organizations strengthen vendor oversight obligations.

Takeaways for Ontario insurers

Together with OSFI Guideline B-13 (Technology and Cyber Risk Management), OSFI Guideline B-10 (Third-Party Risk Management), and FSRA's GR0016INT (IT Risk Management Guidance), PC0050APP reinforces a consistent regulatory expectation: boards are accountable for operational risk, risk management frameworks must be documented and proportionate, third-party accountability cannot be outsourced, and resilience must be demonstrated through tested plans rather than asserted. For Ontario-incorporated insurers, PC0050APP provides the framework through which FSRA will assess operational risk and resilience during supervisory reviews.

Key takeaways include:

(1) Governance accountability cannot be delegated.

The Board bears ultimate responsibility.
Risk appetite statements, ORMF approval, and BCP/DRP oversight must be demonstrably Board-level activities.
Ontario insurers should assess their governance structures against Principle 1 and document any gaps.

(2) Cyber and IT controls will face direct scrutiny from FSRA.

FSRA will assess the full lifecycle of IT risk management from access controls and network security through to incident reporting and staff training.
Insurers should benchmark their programs against GR0016INT. The 72-hour material incident notification window for Ontario insurers under GR0016INT is a compliance tripwire worth confirming in internal procedures.

(3) Outsourcing does not outsource the risk.

Accountability for third-party risks stays with the insurer.
Vendor contracts, particularly with cloud service providers, should be reviewed for incident notification obligations, audit rights, concentration risk provisions, and BCP/DRP integration.

(4) BCPs and DRPs must be tested and producible on demand.

FSRA may require insurers to present BCPs, DRPS, and scenario testing results during supervisory monitoring.
Plans must be current, scenario-tested, and capable of being produced promptly.

(5) Climate is a growing supervisory priority, and should be acted upon before the next guidance is anticipated to come out (2031).

FSRA has signalled that additional climate and ESG guidance is coming, and already factors ESG initiatives into the Resilience Rating.
Ontario insurers that have not yet begun embedding climate risk into corporate strategy should start now.

Just over the horizon: 2025 annual report of the OSC’s Investor Advisory Panel

Wed, 08 Jul 2026 00:00:00 Z

The Ontario Securities Commission’s Investor Advisory Panel released its 2025 Annual Report (IAP Report) in May, suggesting that investor protection should continue to shape the regulatory agenda, including through regulatory initiatives aimed at innovation, capital formation and competitiveness. The IAP Report emphasizes that retail investors are operating in an increasingly complex environment marked by more product choice, technological change, social media influence and increased fraud risk, and it repeatedly frames investor protection as essential to each branch of the OSC’s mandate.

For registrants, one important theme is the focus on retail facing digital practices. The IAP highlights concerns about do-it-yourself (DIY) investing, the growing use of AI and social media in investment decision making and digital engagement practices such as push notifications, contests, rewards programs and trending asset lists. It supports additional safeguards, cautions against harmful digital engagement practices and encourages regulators to consider whether further measures are needed in relation to finfluencers.

The IAP Report also notes the expansion of Exchange-Traded Funds (ETFs), with 2025 marking the first time ETF launches outpaced mutual fund launches, including more complex and digital asset related products, and stresses that disclosure regarding such products must be clear, accessible and useful to investors. The IAP Report also raises concerns more generally about inconsistent compliance with the Client Focused Reforms (CFRs), including deficiencies in risk profiling, “Know Your Product (KYP)” processes, suitability assessments and training.

Finally, the IAP Report underscores two broader developments relevant to firms’ risk management frameworks: modernized enforcement actions and renewed attention to investor redress. The IAP calls for expanded enforcement tools and strategies in response to increasingly sophisticated fraud, including AI-enabled scams, and reiterates its long-standing support for binding decision-making authority for the Ombudsman for Banking Services and Investments (OBSI), along with clearer and more effective redress mechanisms for harmed investors.

The authors would like to thank Ray Zhao, student-at-law, for her contributions to this insight.

Access model for continuous disclosure documents finalized by Canadian Securities Administrators

Wed, 08 Jul 2026 00:00:00 Z

A new access model for certain continuous disclosure documents of non-investment fund reporting issuers (the Access Model) has been finalized by the Canadian Securities Administrators (CSA) through amendments to National Instrument 51 102 Continuous Disclosure Obligations and National Instrument 54 101 Communication with Beneficial Owners of Securities of a Reporting Issuer.

Provided all necessary approvals are obtained, the amendments are expected to come into force on Sept. 22, 2026, reflecting a continued shift toward digital disclosure in Canadian capital markets.

Takeaways

An electronic access model that enables non-investment fund reporting issuers to deliver annual financial statements, interim financial reports, and related management’s discussion and analysis (MD&A) (collectively, CD Documents) will come into force on Sept. 22, 2026.
The Access Model is voluntary and may be used to deliver certain CD Documents while existing delivery requirements continue to apply to others, providing issuers with flexibility in how the framework is adopted.
Issuers who adopt the Access Model must follow a structured notification framework, including advance notice before adopting the model, news release and website disclosure requirements, and ongoing investor disclosure requirements to ensure continued awareness of how to access CD Documents electronically.
Investors will continue to be able to request and obtain copies of CD Documents without charge. Existing standing instructions to receive documents in electronic or paper form will continue to be honoured.
The Access Model operates alongside, rather than replaces, the existing notice-and-access framework.

Background: How the Access Model came to be

Under the existing framework in Canadian securities legislation, reporting issuers are required to annually provide investors with an opportunity to request certain continuous disclosure documents in either electronic or paper form.

In 2022, the CSA proposed an access based model for both prospectuses and CD Documents. While the prospectus access model came into force in 2024, the CSA deferred implementation of the continuous disclosure model following feedback that additional investor protection measures were required.

Subsequent amendments were republished for comment in 2024, incorporating changes to address investor awareness and accessibility concerns. During the second comment period, all commenters expressed general support for the proposed amendments, noting that the Access Model balances reduced regulatory burden with continued investor access to information.

How the Access Model works: Filing, notification and disclosure requirements

Under the Access Model, electronic access is deemed to have been provided where the issuer complies with prescribed requirements:

Filing the CD Document on SEDAR+;
Issuing a news release no later than one calendar day after filing, announcing that the CD Document is accessible electronically. The news release must include specific disclosure regarding how the CD Document can be accessed on SEDAR+, how investors can request a copy of the CD Document, and confirmation that any standing instructions for delivery in electronic or paper form will continue to be honoured. It must also notify investors of the availability of the SEDAR+ notification functionality, which allows investors to subscribe to receive email notifications when the issuer files relevant CD Documents on SEDAR+. The required disclosure may be included with other information in a news release; and
Posting the CD Document on the issuer’s website or providing a direct hyperlink to the CD Document on SEDAR+ no later than two calendar days after filing. The issuer must also include a prescribed statement about electronic access on its website. Companion policy guidance indicates that posted documents should remain available at least until the documents for the next financial period are posted, and that the required website statement should appear on the same webpage and near the documents or SEDAR+ link.

If a reporting issuer is using the Access Model for the first time, it must issue a news release at least 25 calendar days before issuing and filing a news release announcing reliance on the Access Model.

In addition to these filing specific steps, issuers relying on the Access Model must provide ongoing disclosure to investors describing the model and how it operates. This includes providing an “annual reminder” statement in proxy related materials, a notice and access package, or a separate accompanying document explaining that CD Documents will be made available electronically, how to subscribe to SEDAR+ notifications, and how to request copies.

If an issuer ceases to use the Access Model, there is no requirement to provide notice. While the annual reminder may be included in notice-and-access materials, the amendments do not otherwise change the existing notice-and-access regime.

Practical considerations for issuers

The Access Model represents a significant step toward digital first disclosure, but its voluntary nature means issuers will need to carefully assess whether adoption is appropriate in their circumstances.

For many issuers, the Access Model may reduce the costs and administrative burden associated with traditional delivery requirements, including printing and mailing CD Documents. While these efficiencies may reduce certain delivery-related expenses, issuers may incur additional compliance costs associated with implementing and maintaining the Access Model. At the same time, adopting the model introduces new operational requirements, including managing timely SEDAR+ filings and related news releases, ensuring required website disclosures are posted within prescribed timeframes, and overall compliance with ongoing disclosure obligations.

While the Access Model reflects increasing investor reliance on electronic disclosure, issuers should consider how changes in delivery practices may be received by investors. Retail investors who rely on traditional delivery methods or who are less engaged with SEDAR+ may require additional communication or education to ensure continued access to information. Issuers may also consider whether to supplement mandatory disclosures with enhanced investor communications (such as website navigation, direct links, or investor email reminders) to mitigate any potential reduction in visibility of disclosure.

The Access Model may be adopted for annual financial statements and related MD&A, interim financial reports and related MD&A, or both. Issuers may also choose to use the model for certain interim reporting periods while continuing to rely on existing delivery requirements for others. At this time, the model has not been extended to proxy-related materials, take-over bid circulars, or issuer bid circulars, and it is not available to SEC foreign issuers and designated foreign issuers.

Finally, issuers should be mindful that the Access Model does not override all delivery obligations. Standing instructions under NI 54-101 continue and are not overridden by use of the model. Investors retain the right to request and obtain copies of documents without charge, and any standing instructions to receive documents in electronic or paper form must continue to be honoured. In addition, issuers may remain subject to separate delivery requirements under corporate law and other applicable requirements, notwithstanding their use of the Access Model.

Next steps

These amendments represent a further step in the CSA’s efforts to modernize disclosure delivery in Canadian capital markets while maintaining investor access to information.

Issuers considering the Access Model should review the new timing, news release, website posting and investor disclosure requirements, assess whether their existing website and disclosure controls support the prescribed deadlines, and confirm whether any corporate law or other delivery obligations continue to apply.

For additional details, see: CSA Notice of Amendments and Changes to Implement an Access Model for Certain Continuous Disclosure Documents of Non-Investment Fund Reporting Issuers.

The authors would like to thank Sarah Spector, summer student, for her contribution in writing this article.

A view from the scenic route: The 2025 OTC derivatives report

Wed, 08 Jul 2026 00:00:00 Z

The Ontario Securities Commission (OSC) released the Canadian OTC Derivatives 2025 Annual Report in May (the Report). The OSC obtains its data from public sources and directly from trade repositories. The Report offers findings of interest regarding Canada’s OTC markets for investment managers and advisers. Interest rate derivatives remained the dominant asset class in Canada’s OTC market, accounting for 88.2 per cent of total gross notional outstanding (GNO) in Q4 2025, with growth driven by swaps and continued adoption of the Canadian Overnight Repo Rate Average (CORRA-CAD) and Secured Overnight interest Rate (SOFR-USD) based products. Canada had 9.2 per cent of the global OTC derivatives market (measured by GNO) in June 2025.

The report also underscores the OSC’s increasing focus on data quality. Amendments to the trade reporting rule that took effect on July 25, 2025, together with compliance related remediation, materially affected reported statistics by improving product classification and removing stale or expired trades.

Looking ahead, the most notable regulatory development is the expansion of mandatory central clearing under NI 94-101 – Mandatory Central Counterparty Clearing of Derivatives and Related Companion Policy, effective March 25, 2026, to cover certain index credit default swap products in addition to updated interest rate derivatives tied to benchmark transition. More broadly, the report suggests the OSC is taking a more granular, risk-sensitive approach to monitoring derivatives markets, including through the use of risk metrics like DV01, which measures the dollar change in a position’s value resulting from a one-basis-point movement in interest rates.

The authors would like to thank Ray Zhao, student-at-law, for her contributions to this insight.

Data centre regulation in Alberta

Wed, 08 Jul 2026 00:00:00 Z

Alberta has emerged as one of Canada’s most proactive jurisdictions for the development of large‑scale data centres, particularly those supporting artificial intelligence (AI). Through a combination of targeted legislation, intergovernmental coordination, and policy direction to energy regulators, the province has adopted a regulatory approach that departs in important respects from the traditional treatment of large industrial electricity loads.

Key takeaways for proponents

Alberta is modernizing its regulatory framework to accelerate approval timelines and incentivize data centre projects that supply their own power.
Alberta offers regulatory flexibility not available in many other Canadian jurisdictions, particularly for self-supplied or hybrid power models.
Data centres may be subject to non‑standard utility connection requirements under regulations permitted under Bill 8, rather than the uniform treatment traditionally applied to large loads.
Early integration of generation, load, and regulatory strategy is critical to managing approval risk.
Federal-provincial alignment improves certainty for large scale AI infrastructure investments.

Alberta’s unique regulatory and policy approach to Data Centres

A foundational feature of Alberta’s approach is the treatment of data centres as strategically significant infrastructure rather than ordinary commercial electricity consumers. Alberta’s Artificial Intelligence Data Centres Strategy positions data centres as critical to economic diversification, innovation, and Canada’s emerging “sovereign compute” objectives. This framing has informed subsequent legislative and regulatory actions aimed at accelerating development while positioning Albertans to benefit from long‑term economic returns. For proponents, this means data centre projects are increasingly assessed through a broader public‑interest lens that extends beyond conventional utility considerations such as load size or connection timing.

Emphasis on “Bring Your Own Power”

Perhaps the most distinctive element of Alberta’s framework is its explicit preference for data centres that supply their own electricity or otherwise add net new generation. Although the Alberta Electric System Operator’s (AESO) interim Phase 1 approach has allocated 1,200 MW for data centre connection requests, provincial policy statements acknowledge that the scale of proposed data centre demand far exceeds the capacity Alberta’s grid can accommodate without affecting reliability or affordability.

As a result, Alberta has signalled that projects which rely primarily on self‑supply—or structured arrangements that avoid drawing on grid capacity—will be prioritized. This approach materially alters the traditional utility connection model. Instead of competing solely through the AESO’s standard system access queue, proponents are encouraged to integrate generation, load, and connection planning from the outset.

There are multiple data centre projects currently under review by the AESO, and a map of data centre connection applications is available on the AESO website. For more information about Alberta’s AI Data Centre Mandate see BLG’s October 2025 article.

Alignment with Federal Policy through the Canada–Alberta MoU

Alberta’s approach is further distinguished by its coordination with federal policy through the recent Canada–Alberta Memorandum of Understanding (MoU). The MoU commits both governments to expanding electricity capacity to support AI and data centre infrastructure and aligns Alberta’s initiatives with Canada’s Sovereign AI Compute Strategy.

Notably, the MoU contemplates federal flexibility in the application of the Clean Electricity Regulations in Alberta, reducing the risk that federal emissions constraints could impede timely access to power for data centre projects.

Expanded (yet uncertain) regulatory flexibility

Recent changes to Alberta law enacted by the Utilities Statutes Amendment Act, 2025 (formerly Bill 8) confer on the Minister of Affordability and Utilities and the AESO broad authority to make rules and regulations in respect of data centres. These tools will presumably be used to enact a framework for accommodating and potentially facilitating data centre connection, although no such framework has yet been announced. Among other things, the Minister may now:

define different classes of data centres
regulate electricity system access,
impose load management or load shedding requirements, and
exempt data centres from requirements under the Electric Utilities Act.

The AESO is also now specifically empowered to make rules regarding data centres. Uniquely among AESO rules, these rules will not be subject to challenge on the grounds that they do not support the “fair, efficient and openly competitive operation of the electricity market”.

The powers conferred by these amendments indicate a clear intention to entrust to the executive branch the connection and accommodation of data centres on the Alberta system, and potentially to chart a new course unconstrained by the rules and principles that have traditionally governed that system. This extraordinary approach empowers the Government to react quickly and decisively to the pace and disruptive potential of intensive data centre development, but the Government has not yet clearly indicated what that reaction will be. The Government’s own announcements to date suggest that a straighter path for data centres through the regulatory approval process would be coupled with requirements that they fund the transmission upgrades that they require, but no detailed approach has yet been announced.

From a proponent’s perspective, Bill 8 introduces both opportunity and uncertainty. While it may create flexibility for innovative connection and power supply structures, it also means that data centre projects may be subject to tailored regulatory conditions that differ from those applied to other large industrial loads. For more about the Canada-Alberta MOU and Bill 8 see BLG’s December 2025 article.

AI Data Centre Computer Hardware Levy

The Financial Statutes Amendment Act, 2025 (No. 2) introduced a 2 per cent levy on computer hardware that applies to grid-connected data centres drawing 75 MW or more. The levy comes into effect Dec. 31, 2026, and the levy will be fully creditable against Alberta corporate income tax. Once a data centre becomes profitable and pays corporate tax, the levy will have no net effect on their tax burden. Alberta has signalled that it may develop other programs for payment-in-lieu-of tax and deferral mechanisms to ease early-stage capital pressures, aiming to strike a balance between capturing public revenue while maintaining Alberta’s appeal as a data centre destination.

The levy contains further incentives for data centre proponents to “bring their own power”: it is reduced to 1 per cent for data centres that are connected to the grid but generate their own power, and off-grid data centres pay no levy at all. For more information about Alberta’s AI data centre levy see BLG’s September 2025 article.

How these features fit into the typical utility connection process

To reduce regulatory friction, Alberta has established a dedicated data centre “concierge” function intended to coordinate approvals across provincial ministries, regulators, municipalities, and Indigenous communities. While this does not replace formal utility or land‑use approvals, it is designed to reduce sequencing risks and avoid delays where electricity connection, generation approvals, and development permits are interdependent.

Unique AESO connection process requirements for Data Centres

The AESO has released data centre–specific connection process requirements that ask applicants to disclose proposed technical and operational characteristics, including load composition, backup generation, and expected operating behaviour. While this disclosure is not currently mandatory, it reflects an emerging framework that the AESO has indicated will be further developed over time.

AESO’s Large Load Integration program - Phases I and II

Phase I of the AESO’s Large Load Integration program concluded in late 2025, successfully allocating the full 1,200 MW interim connection capacity to two connection projects. During Phase I, the AESO incorporated a degree of flexibility in response to proponent feedback, including the establishment of a trading window that permitted the exchange of MW allocations prior to final assignment.

All remaining large load requests will be considered in Phase II of the Large Load Integration program. Phase II is also intended to inform the development of a long‑term framework applicable to all large loads, including data centres, with a particular focus on the “bring your own generation” model and the regulatory connection process. Integration considerations will span the AESO’s full mandate, including connection processes, system planning, operations, markets, tariff design, and reliability.

Protecting grid reliability and ratepayers

A consistent theme across Alberta’s and the AESO’s policy statements is the protection of grid reliability and electricity affordability for existing consumers. Alberta has been clear that data centre projects must bear the costs associated with their system impacts and should not shift those costs onto ratepayers. This principle underlies Alberta’s willingness to impose differentiated connection requirements or financial mechanisms for grid‑connected data centres, reinforcing political and regulatory support for accelerated development while striving to maintain public confidence in the electricity system.

Impact of Alberta’s Restructured Energy Market

The Restructured Energy Market (REM) – a comprehensive overhaul of Alberta’s power market intended to stabilize prices and enhance reliability – is slated to launch in 2027. The policy and design work are complete, but steps remain to operationalize the new structure and finalize tariffs and rate classes. These changes will directly impact project economics for grid-connected data centres and could reshape how data centres and other large industrial customers buy, generate, or sell electricity.

Data centre regulation in British Columbia – Competing for a limited supply

Wed, 08 Jul 2026 00:00:00 Z

British Columbia recently introduced legislative amendments that will restrict the electrical capacity available for new data centre projects within the Province. As of Feb. 1, 2026, the allocation of new electrical capacity for data centre purposes in British Columbia is subject to system-wide aggregate limits that are allocated under a competitive process administered by the British Columbia Hydro and Power Authority (BC Hydro).

As outlined below, these limits are both quantitative and structural in nature. For the two-year period starting Feb. 1, 2026, BC Hydro is restricted to making available a total of 100 MW of new electricity capacity for conventional data centre purposes and 300 MW of new electricity capacity (plus any unused capacity from the conventional data centre limit) for AI data centre purposes. Further, no single project can be allocated more than 145 MW of capacity.

Taken together, these modest limits, coupled with the need to compete with other projects for a finite supply, will have major implications for proponents looking to develop or expand data centre facilities in British Columbia.

Regulatory framework

These changes are rooted in recent amendments to British Columbia’s electricity regulatory regime. The Utilities Commission Act, administered by the British Columbia Utilities Commission, is the principal legislation governing the supply of electricity to data centres in British Columbia.

On November 27, 2025, Bill 31, Energy Statutes Amendment Act, 2025 received Royal Assent and came into force. In broad terms, the Act made key amendments to the Utilities Commission Act to empower the provincial government to depart from the existing “first-come, first-served” electricity service model to prioritize certain industries over others for the stated purpose of ensuring electricity access brings the greatest benefit to British Columbia. More specifically, the amendments permitted the creation of limits on the electrical capacity available to cryptocurrency, data centre, and hydrogen-for-export facilities, which the Province identified as being energy intensive while generally providing fewer jobs and less revenue than natural resource projects.

Limits on available electricity capacity

These legislative changes were operationalized through regulation in early 2026. On Feb. 1, 2026, the Data Centre and Hydrogen Production Facility Power Supply Regulation (the Supply Regulation) came into force. The Supply Regulation introduces limits on the allocation of new electrical capacity for data centres and hydrogen-for-export facilities.

For data centres, the Supply Regulation distinguishes between two categories of facilities. Specifically, it applies to:

conventional data centres (data centres, other than an AI data centres, the primary purposes of which is storage or processing of electronic data); and
AI data centres (defined to mean data centres, other than a cryptocurrency mining project, in which 10 percent or more of the electricity supplied to the facility is or will be used for: (i) computational tasks related to artificial intelligence; (ii) processing and storing data related to the computational tasks in (i); or (iii) powering equipment and infrastructure used for the purposes referred to in (i) or (ii)).

Within these categories, the Supply Regulation establishes aggregate limits on the total amount of new electrical capacity that BC Hydro may make available for data centre purposes. Specifically, for the two-year period commencing on February 1, 2026, BC Hydro cannot make available more than:

a total of 100 MW of new electricity capacity for conventional data centre purposes; and
the aggregated total of: (i) 300 MW of new electricity capacity; and (ii) any electricity capacity not made available under the limit for conventional data centre purposes, for AI data centre purposes.

These limits are further tightened over time. For the one-year period between Feb. 1, 2028 and Feb. 1, 2029, these limits will be cut in half: 50 MW (for conventional data centre purposes) and 150 MW plus any capacity not used for conventional data centre purposes (for AI data centre purposes). The Supply Regulations also provide that a single request for service cannot exceed 145 MW of capacity.

Competitive allocation process

Capacity limits are only one part of the new regime. The Supply Regulation further requires BC Hydro to establish and conduct a competitive process for the allocation of new electricity capacity for data centre purposes.

In response to this requirement, on Jan. 30, 2026, BC Hydro and the Government of British Columbia formally announced a 2026 Call for Demand for Emerging Industries (the Call for Demand) to fulfill the competitive process requirement for data centres for the two-year period starting Feb. 1, 2026. The Call for Demand establishes the following eligibility requirements:

Size of request: The request must be for electrical service of 10 MW or greater, but not more than 145 MW of capacity.
Location: The project must be located within BC Hydro’s service area.
Type of Request: The project must be a new facility not yet interconnected to the BC Hydro grid or must be for (i) incremental capacity; or (ii) a change in end use of electricity supply at an existing facility.
Facility Type: Conventional data centre or AI data centre.
Interconnection: The project is or will be directly or indirectly interconnected to the BC Hydro grid, either via the distribution system or transmission system.
Interconnection Queue: As of Feb. 1, 2026, the project is: (a) in BC Hydro’s transmission or distribution interconnection queue but has not yet signed a facilities study agreement (transmission) or paid a design deposit (distribution); or (b) not yet in BC Hydro’s interconnection queue.

Applicants must also meet certain minimum criteria, including financial capacity and readiness to support the proposed project, as well as a willingness and ability to curtail electricity demand on 24 hours’ notice.

From a timing perspective, the deadline for initial applications and bid security ($25,000 per MW requested) was March 9, 2026. Eligible applications will be assessed based on criteria established by BC Hydro, including the cost-effectiveness for BC Hydro, economic development and community benefits, data sovereignty, First Nations benefits, and environmental benefits.

Looking ahead, it is expected that a further competitive process will be established for the period commencing Feb. 1, 2028 to Feb. 1, 2029.

Other data-centre-specific regulation has been limited to date

Beyond electricity supply, data centre‑specific legislation in British Columbia has been slow to develop. Apart from recent amendments to the Utilities Commission Act, there has been limited targeted regulation directed specifically at data centre development.

Conclusion

In practical terms, the modest 300 MW and 100 MW total allocation for AI and conventional data centres (and 145 MW single-project limit) will likely constrain the growth of the industry in British Columbia. This is particularly notable when compared with other jurisdictions, where individual projects often require significantly higher loads.

By way of comparison, in June 2025, the Alberta Electric System Operator (AESO) introduced an interim connection limit of 1,200 MW for large load projects until 2028. The AESO recently announced it has allocated all 1,200 MW to two projects, one requiring 970 MW and the other 230 MW, with other proposed projects contemplating load requirements of up to 1,800 MW.

As a result, proponents in British Columbia need to be aware of potential barriers to obtaining the electricity service required to power their projects. Where grid‑supplied electricity is unavailable, power may need to be generated “behind the fence,” through renewable or conventional means (such as natural gas), which can give rise to secondary risks, including potential impacts under the Clean Electricity Regulations (CER) introduced in 2025, see our prior bulletin for more on the CER: Canada's new Clean Electricity Regulations | BLG.

Finally, the limits do not only apply solely to new projects. Requests for incremental capacity or changes in end use are also subject to the limits and competitive allocation process. Accordingly, proponents considering expansion or acquisition of existing facilities will need to carefully assess the risk of being unable to secure additional grid‑supplied electricity.

Data centre regulation in Ontario

Wed, 08 Jul 2026 00:00:00 Z

In Ontario, Canada’s most populous province, the development and connection process for data centres is driven by Ontario-specific electricity rules and institutions. Grid access and connection obligations are governed primarily by the Electricity Act, 1998,¹ the Ontario Energy Board’s (OEB) Transmission System Code² (TSC) and Distribution System Code³ (DSC), and the Independent Electricity System Operator’s (IESO) connection approval and market participation requirements.

Recent policy initiatives, such as Bill 40, signal increasing scrutiny of large “specified load facilities” and the potential for proponents to fulfill additional provincial requirements before seeking to connect.

For proponents considering a data centre project in Ontario, a practical first step is to pose a threshold question:⁴ will the facility be transmission-connected (typically >50 kV) or distribution-connected (<50 kV)?

The answer largely determines the process that will follow. The checklist below highlights the key considerations relevant to data centre proponents in Ontario:

Checklist for a transmission-connected data centre (IESO-controlled grid)

Select a candidate connection area and engage early with the transmitter and the IESO to confirm which connection assessment and approval (CAA) processes apply, expected study scope, and realistic in-service dates.
Initiate and complete the key connection studies typically on the critical path for large loads: an IESO System Impact Assessment (SIA) and a transmitter-led Connection/Customer Impact Assessment (CIA). These studies identify any potential network upgrades and technical requirements.
Plan for cost responsibility and security/financial arrangements for network upgrades and connection assets, including timing risks and potential OEB leave-to-construct applications if upstream reinforcements are required.
Negotiate and execute the core connection documentation, including connection agreements and related construction/operating arrangements, in accordance with the TSC and IESO requirements.
Complete IESO market/program registration and authorization steps that can apply to entities connecting to the IESO-controlled grid, including organization registration, authorization and required roles, even where the facility is primarily a load.
Confirm whether evolving provincial policy could impose additional prerequisites for “specified load facilities”, such as data centres meeting criteria set out in regulation under Bill 40-type authorities, as will be addressed later in this insight.

Checklist for a distribution-connected data centre (LDC connection under the DSC)

Identify the relevant local distribution company (LDC) licenced to distribute electricity for the proposed site⁵ and confirm available capacity, preferred connection voltage, and any local expansion constraints.
Submit the LDC’s connection application and progress through the DSC-governed connection process, including the LDC’s technical review, any required expansion design, and the connection agreement.
Address cost responsibility for distribution expansions and connection assets under the DSC, including allocating costs between the customer and the distributor. Reflect these in project economics and schedules.
Where the distribution connection has bulk-system implications, confirm whether IESO/transmitter studies (e.g., SIA/CIA) are also required.
Plan for metering, settlement and rate class considerations, including whether a new or modified rate class could be proposed for large data centre loads and any applicable distributor conditions of service.
As with transmission connections, monitor emerging provincial requirements applicable to large data centres, e.g., “specified load facility” prerequisites, that could affect connection timing and approvals.

Strict confidentiality over new investments, early connection queue searches prior to committing to site acquisition and development and ongoing diligence and monitoring is strongly encouraged to mitigate the risk of third parties submitting connection study applications (even without the site owner’s authorization or consent) to secure a spot in the queue ahead of a proponent in an effort to extract negotiated concessions in return for dropping their application.

Bill 40

On Dec. 11, 2025, legislative amendments to the Electricity Act, 1998⁶ came into force that contemplate changes to prioritize and approve connection requests from data centre projects deemed to serve the province's economic interests.

Much of the substantive detail is expected to be addressed in forthcoming regulations, including the criteria for defining a “data centre” for these purposes. Materials posted to the Environmental Registry suggest that the factors to be considered in prioritizing data centre connection requests may include: electrical connection size, assessments of community economic benefits, data sovereignty considerations, approval timelines, impacts on the grid, costs to utilities and ratepayers, and whether the establishment of a new rate class would be appropriate.

At this stage, it remains unclear how this contemplated prioritization will operate in in practice: whether timelines will be shortened, whether data centres will receive differentiated treatment in system planning, how preferred sites will be signalled, and whether priority will extend to system upgrade construction.

IESO system planning

The IESO is responsible for planning and preparing the electricity system to meet future needs, including electricity demand forecasting in Ontario.⁷ In its July 2025 paper, “IESO Demand & Conservation Planning Technical Paper: Large Step Loads”,⁸ the IESO characterizes data centers as “large step loads”, defined as loads exceeding 20 MW that connect in large blocks over short timeframes.

The IESO further categorizes data centers into three types:

Enterprise data centres - data centres dedicated to large cloud providers, which include Amazon, Google, and Microsoft.
Colocation data centres - data centres where the owner leases server space to multiple businesses, known as offtakers.
Hyperscale data centres - data centres which contain at least 5,000 server racks and 10,000 square feet of floor space.

As construction timelines are typically measured in months rather than years, and server capacity can be increased rapidly as demand materializes, electricity system impacts can emerge quickly. Ontario's planning frameworks are adapting to accommodate both the scale and pace of these developments.

The OEB appears to be anticipating these impacts with the creation of the Centralized Capacity Information Map,⁹ which provides data about the province’s electrical grid capacity for both load and DER connections. This can guide data centre proponents in evaluating and selecting potential sites.

Impact assessments

For new or modified generation and load facilities with a capacity greater than 10 MW connecting to the IESO controlled grid, proponents are required to complete both an IESO System Impact Assessment¹⁰ (SIA) and a transmitter led Connection Impact Assessment (CIA).¹¹

The SIA and CIA processes can take more than 12 months to complete and require payment of associated assessment fees. Whether SIA/CIA timelines for data centres can be accelerated remains unclear. And prioritizing these projects will likely extend wait times for others.

Market renewal

On May 1, 2025, Locational Marginal Prices (LMPs) replaced the Hourly Ontario Energy Price (HOEP).¹² LMPs represent the value of electricity at specific locations in Ontario's power system, whereas HOEP was a uniform rate. Market Renewal was designed to encourage efficient resource dispatch and investment in areas where electricity is needed most.

The use of location based electricity pricing in Ontario means that the introduction of a large data centre load in a particular area may have adverse pricing implications for other customers served from the same part of the system. Moreover, market renewal could pose challenges for data center proponents to accurately forecast electricity prices, typically one of their largest input costs, when evaluating project economics.

IESO technical requirements

On May 14, 2026 the IESO posted its draft technical requirements for large computational loads connecting to the Ontario system, commonly associated with data centres (the Technical Requirements).¹³ This draft consolidates existing technical requirements for general load facilities and introduces new requirements to address potential adverse impacts on system reliability caused by the associated behaviours of large computational loads.¹⁴

The IESO indicates that connection applicants for large computational load projects should follow the established “IESO Connection Assessments and Approval Process”¹⁵.¹⁶ Projects must comply with all applicable requirements set out in the IESO Market Rules, the TSC, the DSC, and other reliability standards referenced in the Technical Requirements.¹⁷

In addition, connection applicants must also provide additional project data, such as a project development plan, primary equipment data, load composition, and voltage and frequency operating ranges.¹⁸ The draft standards also introduce interconnection technical requirements tailored to address specific load behaviours of large computational loads, to maintain the reliability of the integrated power system.¹⁹

Collectively, the addition of these new technical requirements increases the compliance and disclosure burden on proponents captured within the ‘large computational load’ category. The IESO notes that these requirements may evolve as its understanding of these loads develops.

The IESO will host a public engagement webinar on July 23, 2026, to present the new technical requirements and provide an overview of stakeholder feedback collected throughout the drafting process.

IESO Project Committee

In response to forecasted energy demand growth across Ontario, and as part of Ontario’s Integrated Energy Plan (IEP),²⁰ the IESO has established the Major Projects Identification Committee (MPIC) process to support the early identification of major projects and strengthen forecasting and system planning.

Data centres are expected to account for 13 per cent of new electricity demand in Ontario by 2035²¹, and MPICs are designed to serve as an early warning system to identify large projects that may drive significant new demand.

How the process works:

Major Project Originators submit project information to the IESO.
The IESO reviews submissions.
Major Project Originators and the IESO work together to verify project details.
Entities that have relevant information pertaining to projects, including but not limited to, provincial ministries or agencies, local distribution companies, municipalities (individually or collectively, Major Project Validators) review submissions, sharing relevant information and updates.
A major projects list is finalized annually and incorporated into electricity system plans and forecasts.²²

Conclusion

In Ontario, connecting a data centre to power extends beyond commercial procurement. Proponents must traverse a regulated connection pathway, involving different gatekeepers and timelines depending on whether the project is transmission- or distribution-connected. In both cases, early site screening should focus on:

realistic capacity and in-service timing,
the likely need for (and duration of) SIA/CIA-type impact studies and associated upgrade scope, and
cost responsibility and financial security for connection and reinforcement work.

Proponents are best positioned by building an Ontario-specific connection workplan early: identify the right counterparty (transmitter vs. LDC), confirm applicable studies and approvals, map upgrade and permitting lead times, and monitor whether "specified load facility" prerequisites will apply as regulations emerge.

Centres de données au Québec : d’une promesse séduisante à un contrôle rigoureux

Wed, 08 Jul 2026 00:00:00 Z

Depuis 2016, le Québec s’est activement positionné comme une destination de premier plan pour les centres de données, en tirant parti de son abondance d’énergie renouvelable, de ses tarifs d’électricité concurrentiels et de son ambition de renforcer la souveraineté numérique. Appuyée par une société d’État qui contrôle la production, le transport et la distribution d’électricité, la province offrait une proposition de valeur convaincante : une énergie à faible coût et un climat naturel froid qui réduit les coûts de refroidissement.

Cette stratégie a porté fruit : le nombre de centres de données a considérablement augmenté au cours des dernières années. Cependant, cette expansion rapide, conjuguée aux difficultés amenées par la transition énergétique et la rareté des ressources, exerce de plus en plus de pression sur les ressources énergétiques du Québec, ce qui a entraîné un changement de politique notable. Ce qui semblait au départ un environnement favorable et prévisible se transforme maintenant en un cadre réglementaire plus restrictif et étroitement contrôlé.

Une série de mesures législatives et réglementaires en témoignent. En effet, le Québec a instauré en 2023 une exigence d’autorisation ministérielle pour les projets de 5 mégawatts (MW) ou plus, ainsi que pour les activités de cryptomonnaie liées à une chaîne de blocs nécessitant un minimum de 50 kilowatts (kW)¹.
S’appuyant sur ces changements, le Québec a adopté, en juin 2025, la Loi assurant la gouvernance responsable des ressources énergétiques et modifiant diverses dispositions législatives² (également appelée projet de loi 69). Cette loi renforce et élargit la maîtrise du gouvernement sur l’attribution de l’électricité, consolidant le rôle du ministre de l’Économie, de l’Innovation et de l’Énergie (le Ministère) dans l’approbation des projets énergétiques de grande envergure et dans l’orientation de la gestion à long terme des ressources.

Une décennie après avoir ouvert ses portes aux grands consommateurs d’électricité, le Québec réajuste maintenant sa démarche. Les exploitants de centres de données contestent de plus en plus les mesures d’Hydro‑Québec, telles que d’importantes propositions de hausses tarifaires et de nouveaux frais de sous-utilisation de la capacité.

Acteurs institutionnels de premier plan

Pour comprendre le cadre énergétique du Québec, il faut bien connaître ses principaux acteurs.

Sur le plan des politiques, le Ministère joue un rôle central. Son mandat consiste à assurer une gestion responsable et intégrée des ressources énergétiques, tout en favorisant le développement économique et la transition énergétique³.

Hydro‑Québec, en tant que service public intégré verticalement de la province, assure la production, le transport et la distribution de l’électricité. Ses activités sont réglementées par la Régie de l’énergie du Québec, laquelle détient une compétence exclusive sur les tarifs d’électricité et les conditions de service. La Régie veille à ce que les tarifs demeurent équitables, et à ce que l’on gère les ressources énergétiques de façon responsable.

Principales dispositions du projet de loi 69 : resserrer le contrôle de l’attribution de l’énergie

Voici un aperçu des principales dispositions du projet de loi 69, qui vise à moderniser le secteur énergétique du Québec :

Surveillance accrue : renforcer le rôle de la Régie de l’énergie dans la supervision des grands projets et l’établissement des tarifs.
Plus grande transparence : exiger une reddition de comptes au public plus claire et une meilleure mobilisation des parties prenantes pour les décisions entourant l’énergie.
Attribution des ressources : mettre à jour les critères d’attribution de l’électricité aux grands consommateurs en mettant l’accent sur une utilisation responsable et des priorités stratégiques, tout en assurant une intégration équilibrée de diverses sources d’énergie afin de réduire la dépendance à l’hydroélectricité.
Intégration environnementale : intégrer des critères environnementaux et sociaux dans le développement et l’attribution des ressources énergétiques.

Pour les installations énergivores, comme les centres de données, le projet de loi 69 apporte plusieurs changements majeurs :

Accès à l’électricité : les nouvelles installations ou les projets d’expansion font l’objet d’une évaluation plus rigoureuse quant à leur concordance avec les priorités provinciales, notamment dans les sphères économique, sociale et environnementale.
Politiques d’attribution : les installations doivent démontrer une utilisation responsable de l’énergie et contribuer à des objectifs stratégiques, tels que la décarbonation ou le développement régional.
Exigences de conformité : des obligations de reddition de comptes et de surveillance accrues garantissent que les grands consommateurs respectent les conditions convenues et aident à atteindre les objectifs énergétiques de la province.
Retards possibles : des examens réglementaires supplémentaires peuvent prolonger les échéanciers des projets, surtout ceux qui entraînent des répercussions environnementales ou sociales importantes (voir ci-dessous).

Projets exigeant une approbation ministérielle

Depuis 2025, Hydro-Québec ou tout autre fournisseur d’électricité doit obtenir l’autorisation du Ministère pour fournir de l’électricité à un centre de données, par exemple, qui demanderait 5 MW d’électricité ou plus pour ses activités, ou encore à un consommateur d’électricité qui demande 50 kW ou plus pour un usage cryptographique appliqué aux chaînes de blocs à des fins de minage de cryptomonnaie⁴. Selon les autorités réglementaires, ce processus de raccordement au réseau vise à garantir que les ressources limitées en électricité sont attribuées aux projets générant les plus grands bénéfices généraux pour la province. Ainsi, le processus n’est plus uniquement technique — il est stratégique et concurrentiel.

1. Dépôt de la demande

Le processus de raccordement au réseau pour un centre de données (ou un projet de minage de cryptomonnaies impliquant des activités de chaîne de blocs) débute par le dépôt d’une demande officielle auprès du Ministère et du fournisseur d’électricité concerné (généralement Hydro‑Québec). Cette demande se veut une présentation officielle du projet; on y précise ses besoins énergétiques, ses caractéristiques techniques, ainsi que les retombées économiques, sociales et environnementales prévues.

2. Examen par le gouvernement et Hydro-Québec

Une fois déposée, la demande fait l’objet d’une évaluation rigoureuse et comparative avec d’autres projets proposés. Comme la capacité électrique est limitée, l’évaluation des projets ne se fait pas selon le principe du premier arrivé, premier servi. Le gouvernement et Hydro‑Québec examinent plutôt conjointement toutes les demandes pour déterminer celles qui utiliseraient l’électricité de la façon la plus efficace et la plus bénéfique.

Dans ce contexte, on accorde une attention particulière à plusieurs facteurs décisifs, comme l’apport économique du projet (la création d’emplois et les investissements, ses répercussions environnementales et sociales, etc.). Les autorités examinent également la demande du projet à la lumière de l’évaluation énergétique globale (pour assurer une gestion optimale de l’énergie), des mesures prévues d’efficacité énergétique, de l’utilisation d’équipement à haut rendement, de l’optimisation du bouquet énergétique (p. ex. l’utilisation d’autres sources d’énergie comme la biomasse, la bioénergie, le gaz naturel ou l’autoproduction), ainsi que de la récupération et de la valorisation des rejets thermiques, entre autres choses.

Fait important, l’évaluation vise à maximiser les avantages par mégawatt consommé, plutôt que de simplement privilégier les projets de plus grande envergure. Autrement dit, les projets démontrant un solide rendement global et une utilisation efficace de l’énergie sont plus susceptibles d’être choisis en premier.

3. Décision et issues possibles

Après l’évaluation, le Ministère prend une décision, qu’Hydro‑Québec fait suivre à l’auteur de la demande de projet. Il y a trois issues possibles :

Tout d’abord, le demandeur pourrait essuyer un refus. En pareil cas, il peut déposer une autre demande.
Deuxièmement, la demande peut être reportée. Cela signifie que le projet demeure en examen, mais qu’aucune décision n’est prise dans l’immédiat. L’auteur du projet peut discuter avec les autorités afin de relever les possibilités d’amélioration et de rehausser la proposition.
Enfin, le projet peut recevoir une approbation préliminaire. Il s’agit d’une acceptation conditionnelle; il y aura d’autres exigences avant l’octroi de l’autorisation finale (voir l’étape 4).

4. De l’approbation préliminaire à l’autorisation définitive

Lorsque l’approbation préliminaire est accordée, le projet doit franchir des étapes supplémentaires. D’abord, le gouvernement envoie une lettre de préautorisation précisant des conditions particulières à satisfaire dans un délai déterminé. Ces conditions peuvent notamment inclure des améliorations au chapitre de l’efficacité énergétique, des éclaircissements sur la démarche de raccordement ou des garanties financières.

Le demandeur est ensuite tenu de collaborer étroitement avec Hydro‑Québec et le gouvernement afin de préparer la documentation requise et de démontrer le respect de ces conditions. Une fois ces exigences satisfaites, le gouvernement rend une décision finale.

Cette autorisation définitive peut inclure des engagements contraignants, comme des échéances pour la conclusion d’une entente de raccordement, des exigences environnementales ou de retombées économiques, ainsi que des jalons importants dans le projet.

Autrement dit, les demandeurs issus des secteurs des centres de données et du minage de cryptomonnaies qui demandent un raccordement au réseau doivent désormais démontrer non seulement que le projet est faisable au point de vue technique, mais aussi qu’il tient compte des enjeux économiques, environnementaux et sociaux liés à sa consommation d’énergie.

Frais supplémentaires pour les performances moins élevées

Outre les contrôles d’accès resserrés, Hydro‑Québec a mis en place de nouveaux mécanismes de tarification pour les grands consommateurs d’énergie.

En 2025, Hydro-Québec a établi de nouveaux frais pour les clients avec contrats à tarif LG, qui visent les clients dont la demande s’élève à 5 MW ou plus (comme les centres de données), et qui n’ont pas utilisé toute l’électricité dont ils disposaient. Selon le tarif applicable, les clients doivent réserver un certain niveau de capacité électrique correspondant à leurs besoins opérationnels. Si cette capacité réservée dépasse nettement l’utilisation réelle, des frais s’appliquent.

Hydro-Québec calcule les frais en examinant la consommation du client au cours des 12 cycles de facturation précédents. Si la demande maximale de puissance du client pendant cette période est inférieure à 60 % de la capacité réservée, des frais sont appliqués. Ceux-ci sont calculés sur la portion inutilisée de la capacité réservée (c’est‑à‑dire l’écart entre la consommation de pointe réelle et le seuil de 60 %).

Ce mécanisme vise à assurer une utilisation efficace de la capacité électrique réservée, mais les parties prenantes perçoivent largement cette mesure comme une pénalité plutôt qu’un tarif traditionnel. Plusieurs exploitants de centres de données ont contesté la validité de ces frais devant la Cour supérieure du Québec, mais on attend toujours qu’elle se prononce sur la question.

Nouvelle proposition tarifaire pour les centres de données et l’exploitation de chaînes de blocs

En février 2026, Hydro‑Québec a annoncé qu’elle entendait proposer à la Régie de l’énergie de nouveaux tarifs pour les grands consommateurs (comme les centres de données), ainsi qu’un rajustement du tarif pour l’usage cryptographique appliqué aux chaînes de blocs⁵. Hydro-Québec déclare qu’elle veut que les centres de données assument une plus grande part des coûts liés à leur forte demande d’électricité, et souhaite aussi gérer de façon responsable la croissance des actifs et capter toute la valeur pour le Québec. Selon Hydro-Québec, les tarifs proposés refléteront le coût des nouveaux approvisionnements tout en demeurant compétitifs sur le marché nord-américain, tandis que l’électricité renouvelable sera mise à contribution.

En janvier 2026, le gouvernement du Québec a entériné l’approche d’Hydro-Québec en exposant à la Régie de l’énergie un ensemble d’enjeux économiques, sociaux et environnementaux, dans les décrets 89-2026 et 88-2026.

Centres de données (tarif CD)

Hydro-Québec a proposé un nouveau tarif CD pour les centres de données qui nécessitent 5 MW ou plus, à un coût moyen d’environ 13 ¢ le kWh — à peu près le double du tarif actuel pour les consommateurs de grande puissance.

Ce tarif s’appliquera automatiquement aux nouveaux projets, sous réserve de l’approbation de la Régie de l’énergie, avec des mesures transitoires pour les installations existantes afin d’assurer la prévisibilité de la consommation d’énergie. Il s’appliquera également à tout centre de données alimenté par Hydro-Québec et qui dispose d’un maximum autorisé de 5 MW ou plus, ce qui comprend les clients actuels qui paient les tarifs M et LG qui atteignent ce seuil.

Hydro-Québec demande à ce que le tarif CD entre en vigueur le 1er novembre 2026. Cependant, de nombreux exploitants et utilisateurs de centres de données ont déjà exprimé leur intention de contester le tarif CD devant la Régie de l’énergie. L’audience est prévue pour l’automne 2026; une décision pourrait être rendue d’ici la fin de l’année ou au début de 2027.

Chaînes de blocs et cryptomonnaie (tarif CB)

Hydro-Québec propose un tarif révisé de 19,5 ¢/kWh pour l’usage cryptographique appliqué aux chaînes de blocs, ce qui reflète la nature énergivore de ces activités et leur empreinte économique limitée. On propose une tarification transitoire sur trois ans aux clients actuels afin de faciliter l’adaptation. Ce tarif est également contesté devant la Régie de l’énergie, en parallèle avec le tarif CD pour les centres de données.

D’un point de vue comparé

Le resserrement par le Québec concorde avec les tendances en Colombie-Britannique et au Nouveau-Brunswick, qui mettent également l’accent sur une attribution prudente de l’électricité selon des critères économiques et environnementaux.

Par opposition, des administrations comme l’Alberta et certains États américains s’appuient davantage sur les combustibles fossiles ou sur une production décentralisée pour répondre à la demande des centres de données, ce qui offre une plus grande flexibilité, mais soulève différentes préoccupations environnementales.

Conclusion : un pivot stratégique avec des implications incertaines

La réglementation des centres de données au Québec a manifestement changé, passant d’une promotion dynamique à une croissance surveillée et sélective.

La province cherche désormais à s’assurer que ses ressources en électricité, quoique largement renouvelables, mais limitées, sont attribuées aux projets les plus bénéfiques d’un point de vue général. Ce changement est motivé par l’augmentation de la demande, la nécessité de gérer les contraintes d’infrastructure et des objectifs politiques plus larges liés à la transition énergétique et à la création de valeur économique.

Parallèlement, ce cadre en évolution laisse place à une plus grande incertitude pour les exploitants de centres de données. Des processus d’autorisation plus stricts, des tarifs plus élevés et de nouveaux frais pour la capacité inutilisée modifient les hypothèses économiques qui avaient attiré ces investissements au départ.

L’issue des contentieux réglementaires en cours devant la Régie de l’énergie et des contestations judiciaires en instance sera un tournant majeur. Elle déterminera si le Québec peut maintenir son attrait tout en exerçant une maîtrise accrue sur ses ressources énergétiques.

Dans les faits, le Québec ne se contente plus de rivaliser sur la base d’une électricité renouvelable à faible coût : il redéfinit les règles d’accès à cette électricité. La question cruciale consiste à savoir si ce modèle mènera à un équilibre durable entre l’intérêt public et l’investissement privé, ou s’il incitera certains acteurs à rediriger leurs projets vers des administrations plus conciliantes.

Data centres in Canada: Current state

Wed, 08 Jul 2026 00:00:00 Z

Data centres have rapidly emerged as a dominant force in global infrastructure investment, accounting for more than 25 per cent of global greenfield investment in 2025. While they generate fewer jobs and contribute less to GDP than other sectors, such as natural resources, jurisdictions across the world are actively seeking to attract these projects to secure data sovereignty, boost national security and bridge tech leadership gaps. Yet as AI reshapes the global economy, a central constraint is emerging: the capacity to site, build, and power data centres at sufficient scale.

Canada is an attractive setting for data centre development, owing to its cold climate, abundance of hydroelectric power and proximity to the United States market. Yet, Canada remains a comparatively small player. As of early 2026, the U.S. boasted 40.6 GW of live data centre capacity, compared to Canada’s modest 1.4 GW of live capacity in September 2025.

What does this mean for data centre proponents seeking to connect in Canada? It depends on the jurisdiction. In Canada, electricity generation, transmission, and distribution are administered by government-owned provincial authorities. Opportunities and requirements vary widely depending on which province you are considering for a new project. This publication examines four provinces and thus four distinct regulatory approaches to data centre development.

From British Columbia, BLG Partner and National Leader of the Environmental Group, Rick Williams, delves into B.C.'s electricity regulatory regime and how recent changes impact data centre proponents. In Alberta, BLG Partner Jordan Hulecki will explore what has made the province one of Canada’s most proactive jurisdictions for the development of large‑scale data centres. Moving east to Ontario, BLG Partner and Professional Engineer Colm Boyle describes recent regulatory developments and measures being taken to ensure the provincial electricity grid is positioned to accommodate new data centre connections. Finally, in Québec, BLG Partner Adina Georgescu provides a general overview of Hydro-Québec’s regulatory framework, the processes governing load connections, and the policies shaping power availability and allocation for energy-intensive facilities.

Regardless of the legal tools used to manage it, grid stress has emerged as the defining constraint across all four jurisdictions, and provincial regulators are unified by a ratepayer-first approach. Alberta's explicit preference for “bring-your-own power” self-supply and B.C.'s behind-the-fence workarounds reflect this pressure, as does Ontario's Impact Assessment requirement for facilities over 10 MW, a process that can exceed 12 months in a sector where construction timelines are typically measured in months, not years. In Québec, Bill 69 introduces scrutiny of new and expanded facilities to align with provincial priorities and responsible energy use.

Across all four provinces, Indigenous consultation is emerging as a criterion in the approval and connection process, particularly in British Columbia. Regulatory frameworks in all four jurisdictions remain in early stages of maturity: Ontario's Bill 40 amendments to the Electricity Act are sparse on detail, with substantive elements deferred to forthcoming regulations, while Québec's Bill 69 includes data centre-specific provisions, including proposed new tariffs and updated allocation criteria, are still working through the Régie de l'énergie.

The greatest divergence across jurisdictions arises from how each province prioritizes access for data centre proponents. Alberta stands apart. Its Memorandum of Understanding with the federal government suspends its Clean Electricity Regulations obligations and explicitly encourages expanded electricity access for made-in-Canada data centres, making it the most openly welcoming of the four. Ontario, Québec, and British Columbia are not closed to data centres, but constrained grid capacity limits how many large connection requests each can absorb. B.C. will make 400 MW available over two years commencing February 2026, capped at 145 MW per project. Ontario requires proponents to bear marginal system costs through connection asset payments, expansion deposits, and participation in locational marginal pricing. Hydro-Québec has proposed a dedicated industrial tariff for data centres requiring more than 5 MW of approximately 13 ¢/kWh - roughly double the current large-power rate.

The benefits of data centre development in Canada are clear. As a result, national and provincial governments are positioning Canada, supported by its strong energy and power bases, cool climate, abundant fibre connectivity and availability of natural resources as an attractive jurisdiction for proponents via competitive power costs and an attractive corporate tax environment. However, successfully developing data centres in Canada requires navigating complex legal and regulatory requirements across jurisdictions. Explore the perspectives below regarding data centres in Alberta, British Columbia, Ontario and Québec to learn more.

Whether you are entering the Canadian market for the first time or scaling existing operations, the regulatory nuance across these four provinces makes early, jurisdiction-specific legal advice essential. Contact any of our authors to discuss your project.

Gas prices are not alone – Regulatory fee increases

Wed, 08 Jul 2026 00:00:00 Z

Several securities regulatory authorities have proposed, or are in the process of implementing, fee increases.

The Ontario Securities Commission (OSC) has proposed amendments to OSC Rule 13-502 Fees and OSC Rule 13-503 (Commodity Futures Act) Fees which, if adopted, will become effective on April 5, 2027. The proposed increases are intended to address a funding gap needed for the OSC to fulfill its mandate, and the notice indicates that a combination of factors such as the evolution of products, market participants and technology require more comprehensive regulatory oversight. Many smaller market participants will benefit from the reduced participation fees, but the largest issuers and registrant firms (i.e. those with Ontario specified revenues greater than C$4 billion) will see an increase. As examples, the amendments will consolidate the bottom two participation fee tiers for registrant firms, resulting in the payment of the lowest annual participation fee of C$700, while introducing new tiers at the top level resulting in a fee of up to C$3,055,500 (from C$2,037,000). Certain activity and maximum late fees will also be increased, and the OSC is proposing to introduce a new annual Consumer Price Index adjustment to both the participation fee tier thresholds and the fees themselves. As an example, the OSC proposes to increase the fee for exempt distribution filings from the current C$350 to C$500. Comments on the OSC proposal are due by July 29, 2026.

The British Columbia Securities Commission (BCSC) has also released a consultation on proposed fee changes to increase some existing fees and change fees for registrants, in order for the BCSC to have a balanced budget for fiscal 2028. Examples of fees that would be increased include fees for firms and individuals to maintain a registration, filing a report of exempt distribution and filing a late insider report. The BCSC expects the changes will increase its fee revenue by approximately C$8 million. Any change would be effective as of April 1, 2027, other than the revised rates for maintaining registration, which would be effective beginning April 1, 2028. Comments on these proposals are due August 25, 2026.

As a reminder, the Autorité des marchés financiers (AMF) has already increased their fees, effective as of June 22, 2026. For more information, please see BLG’s Insight.

Navigating the next turn: The RIE Division of the OSC sets out its 2026-2027 examination priorities

Wed, 08 Jul 2026 00:00:00 Z

The Registration, Inspections and Examinations Division (RIE) of the Ontario Securities Commission (OSC) has published its examination priorities for fiscal 2026-2027 in OSC Staff Notice 33-761 – 2026 Examination Priorities for the Registration, Inspections and Examinations Division, enforcing its focus on a risk-based supervisory framework that is responsive to evolving market conditions and emerging risks. These priorities are informed by findings from ongoing regulatory oversight, in collaboration with other OSC divisions and regulatory partners, developments in capital markets and engagement with registrants and other stakeholders. RIE has emphasized that it will focus on areas presenting increased risk of investor harm or market disruption. Speaking of which, RIE is itself exploring the use of artificial intelligence (AI) to enhance its examination processes while maintaining effective regulatory oversight.

For registered advisers, dealers and investment fund managers, RIE’s continued emphasis on proportionate and agile oversight has important implications. RIE will maintain a risk-based examination approach, placing emphasis on firms identified as high-risk or high-impact through the Risk Assessment Questionnaire (RAQ) (which was due for completion by June 17). High-impact firms are those with considerable assets under management or where a material operational issue could create systemic risk to the Canadian capital markets. High-risk firms identified through the data collected from the RAQ are risk ranked based on multiple factors.

RIE will also continue to assess compliance with both new and existing regulatory requirements. In particular, derivatives dealers will be examined for compliance with National Instrument 93-101 Derivatives: Business Conduct, which came into force in September 2024. Examinations will focus on how firms have organized and overseen their derivatives business, including supervision structures, over-the-counter (OTC) derivatives trading, communications monitoring and interactions with counterparties to support fair dealing outcomes. RIE will also examine registrants’ capital market participation fees and excess working capital filings to ensure that firms are meeting applicable capital obligations and paying required fees.

RIE is expanding its examination activities to address emerging areas of risk and evolving market practices, including working with the Canadian Investment Regulatory Organization (CIRO) to review separately managed accounts of dealer member firms to identify risks, emerging trends and areas for improvement. Of note, RIE will conduct a national sweep of marketing practices, assessing both traditional and digital marketing activities for compliance with Ontario securities law. The findings of the sweep will help determine whether any updated regulatory guidance is warranted. Registrants will want to ensure that their policies and procedures, oversight, performance advertising and disclosure practices are up to date. For some practical tips see our reminder elsewhere in this newsletter “Buckle up for marketing scrutiny”.

RIE has initiated a compliance initiative focused on registrants’ use and implementation of AI systems (the AI Initiative). The first part of the initiative included a survey of registrants, with certain firms undergoing a further review to assess whether they are complying with securities legislation. Consider including time in your next road trip to catalogue the ways in which your firm and employees use AI and ensure you have an AI use policy, including if your firm does not yet permit the use of AI.

RIE will also publish the results of a focused examination of registrants’ cybersecurity practices conducted in collaboration with the CSA in the second quarter of this fiscal year, summarizing key observations, identified findings, and examples of effective practices.

RIE continues to monitor “ramp-and-dump” stock manipulation schemes and account intrusions and will assess the adequacy of registrants’ controls in addressing these risks.

Finally, RIE has underscored its intention to take swift and decisive regulatory action in response to compliance concerns. RIE has emphasized that the use of “for cause” examinations are critical to deterring misconduct and that it will use all available regulatory tools to address non-compliance, including referrals to its Registrant Conduct team.

The authors would like to thank Ray Zhao, student-at-law, for his contributions to this insight.

New CIRO guidance on “fit and proper”: Checkpoints ahead

Wed, 08 Jul 2026 00:00:00 Z

On June 24, the Canadian Investment Regulatory Organization (CIRO) published new Guidance on the Fit and Proper Test for Approved Persons (GN-9200-26-001) (the Guidance), replacing the Oct. 14, 2021, IIROC Guidance Note on this issue.

The Guidance reiterates that CIRO will evaluate individual Approved Persons applications to determine whether an individual is suitable, or “fit and proper,” on the basis of three fundamental criteria: integrity, financial solvency and competence, while also considering whether registration is in the public interest or is otherwise objectionable.

Factors registration staff (Staff) will consider when evaluating an individual’s integrity include whether the individual was convicted of any offence, with particular weight given to offences of dishonesty, fraud, financial crime or other offences under legislation relating to securities, financial services, insolvency, insurance, consumer protection, money laundering, market manipulation or insider trading, and whether the individual was the subject of any complaints relating to regulated activities. Factors Staff will consider when evaluating financial solvency include whether the individual has been the subject of any judgment debt or award that remains outstanding, if the applicant has filed for bankruptcy, or if the applicant failed to meet a material financial obligation as it came due. When considering competence, Staff will assess whether the individual satisfies the applicable minimum CIRO proficiency requirements and whether they have demonstrated by education, experience and training that they would be able to perform the regulated activity. The full list of factors on how Staff evaluates the three fundamental criteria, and whether approval is contrary to the public interest or objectionable, is set out in the Guidance.

The Guidance also notes that, where Staff has concerns about an individual, they may recommend refusal, revocation, suspension or imposing terms and conditions on their approval/registration, along with indicating that imposition of terms and conditions may be recommended where enhanced supervision or other protective/corrective measures are appropriate. A more extensive review may occur if an approval or registration application contains disclosure on Form 33-109F4 Registration of Individuals and Review of Permitted Individuals under item 12 (Resignations and Terminations); item 13 (Regulatory Disclosures); item 14 (Criminal Disclosures); item 15 (Civil Disclosure) or item 16 (Financial Disclosure). CIRO expects that certain supporting documents will accompany the application for registration, with the specific document required depending on which of the items listed above are disclosed – for example, an unsatisfied debt obligation may require the applicant to produce evidence of the debt amount and repayment plan.

Finally, the Guidance provides best practices to assist Dealers in conducting due diligence on prospective Approved Persons, which includes obtaining explanations from the applicant regarding any client complaints and ensuring applicants understand the questions in Form 33-109F4. Dealers are cautioned that failure to take reasonable steps to conduct due diligence may put into question the Dealer’s own ongoing fitness for registration.

At the crossroads: Proposed amendments regarding insider reporting requirements

Wed, 08 Jul 2026 00:00:00 Z

Earlier this spring, the Canadian Securities Administrators (CSA) proposed amendments to certain exemptions from insider reporting found in National Instrument 55-104 Insider Reporting Requirements and Exemptions (NI 55-104). The amendments are intended to clarify that the insider reporting regime applies to certain transactions involving investment funds and structured products, like structured notes and Canadian Depositary Receipts, that are based on securities of a reporting issuer. The amendments are meant to clarify that an existing exemption in NI 55-104 from having to file reports would not be available to reporting insiders for transactions in these products, on the basis that securities of the relevant reporting issuer form a material component of the fund’s market value and should be subject to the insider reporting regime. For example, single-issuer exchange traded funds and certain structured products provide economic exposure that is equivalent to investing in the securities of a reporting issuer directly. The comment period closed on June 8, 2026.

Québec’s 2026–2050 integrated energy resource plan: Capital build-out, timelines, and market opportunities

Wed, 08 Jul 2026 00:00:00 Z

Québec’s 2026–2050 Integrated Energy Resource Management Plan (PGIRE) is the province’s first fully integrated long-term energy planning framework. It was adopted following a multi‑year legislative, regulatory, and consultation process initiated in 2024–2025 and seeks to operationalize the provincial government’s new statutory mandate to coordinate energy policy, system planning, and decarbonization objectives under a single governance instrument.

Key highlights

Total additional investments by 2050: approximately 87 billion dollars (real, 2024) to deliver the targeted transition, including generation, transmission, distribution, bioenergy, hydrogen and carbon capture and storage-enabling infrastructure, and customer-side efficiency and flexibility
New renewable energy: near 150 TWh by 2050 (electricity ~100 TWh; bioenergy ~50 TWh), plus about 50 TWh of electric efficiency gains to reduce system costs and peak pressures
Electric supply trajectory: ~15 TWh by 2030; ~60 TWh by 2040; ~100 TWh by 2050 (Hydro-Québec), with diversified portfolios and increased storage and demand-side flexibility
Capacity build: wind 12–16 GW by 2040 and 21–25 GW by 2050; solar 1–3 GW by 2040 and up to 5 GW by 2050; hydro uprates/modernizations and new complexes (about 15-year development cycle)
Peak and flexibility: potential need for up to 22 GW of additional peak coverage by 2050, drawing on bi-energy, demand response, storage (including pumped storage and grid-scale batteries), behind-the-meter storage, and vehicle-to-grid as it matures
Bioenergy: cumulative addition of 11 TWh by 2030, approximately 30 TWh by 2040, and approximately 50 TWh by 2050; forest bioenergy alone targeted at approximately between 18 and 20 TWh by 2050
Hydrogen and renewable gases: measured growth to 2050; hydrogen need could reach about 9 TWh; progressive greening of the gas network with renewable natural gas (RNG) and other renewable gas
Network development: long-term transmission plan aligned to the distributor’s supply plan; Hydro-Québec signals eventual addition of about 1,000 km of new lines and five substations
Governance and timing: Hydro-Québec and gas distributors must file 10- to 15-year supply plans consistent with the PGIRE; the Régie de l’énergie’s mandate now expressly includes enabling an orderly, least-cost transition and maximizing economic, social, and environmental benefits

Québec’s PGIRE: An overview

The PGIRE originates directly from An Act to ensure the responsible governance of energy resources and to amend various legislative provisions (Bill 69), adopted on June 7, 2025, which formally required the government to establish and implement a long-term integrated energy plan to guide supply, demand, and investment decisions across all energy vectors.

This act repositioned both the Ministry of Economy, Innovation and Energy and the Régie de l’énergie, expanding their mandates to align tariff-setting, infrastructure planning, and procurement decisions with long-term energy transition objectives.

The PGIRE sets a long-term roadmap centered on energy security, affordability, and an orderly transition, anchored by approximately 87 billion dollars (in 2024 dollars) in additional investments to 2050.

The plan targets roughly 150 TWh of new renewable energy by 2050 (about two-thirds electricity and one-third bioenergy), complemented by about 50 TWh of electricity efficiency gains. Hydro-Québec is tasked with adding about 100 TWh of new electricity supply by 2050 (near 295 TWh total after efficiency), sequenced through intermediate milestones in 2030 and 2040, alongside significant grid reinforcements, storage and peak management tools.

The plan also contemplates expanded wind (up to 21–25 GW by 2050), solar (up to 5 GW by 2050), new hydro (with 15-year lead times), thermal options as system insurance, growth of bioenergy (about 50 TWh by 2050, including 18–20 TWh forest bioenergy), and measured development of hydrogen and gas of renewable origin.

Transmission and distribution planning is to be integrated into 15-year cycles, with Hydro-Québec indicating the transport plan may add about 1,000 km of transmission lines and five new substations over time.

What this means for energy producers (developers, IPPs, OEMs, utilities, storage providers)

Pipeline visibility and scale:
- Sequenced targets to 2030, 2040 and 2050 for new electricity, bioenergy create line-of-sight for large-scale wind, solar, hydro refurbishments or new builds, and storage (batteries and pumped storage) projects.
- Ramping up of wind and solar implies sustained procurement, local manufacturing opportunities, and partnerships under community-participation models adopted by Hydro-Québec in recent wind procurement.
Grid and interconnection:
- Hydro-Québec’s 15-year transmission plan aligned with supply expansion, including planned additions of lines and substations, pointing to ongoing interconnection and network upgrade opportunities.
- Interties with neighbouring systems (Ontario, Maritimes, U.S. Northeast) remain strategic for seasonal exchanges.
Gas and low‑carbon fuels: Growth of renewable gas (notably RNG) leverages existing gas networks; hydrogen growth and potential dedicated distribution where justified present project pathways and offtake structures for industrial heat, mobility, and synthetic fuels.
Bioenergy scale‑up: Targets for forest and other bioenergies signal demand for feedstock aggregation, conversion facilities, logistics, and combined heat and power projects; intermediate milestones in 2030 and 2040 support staged development.
Storage and flexibility: System need for substantial peak coverage and flexibility underpins requirements for storage, aggregated demand response, behind‑the‑meter assets, networks, and vehicle-to-grid pilots scaling over time.

Practical takeaways for energy producers

Prepare for multi-track procurements with community participation features.
Build Québec content and supply-chain strategies tied to PASQÉ‑type platforms (plateformes d’approvisionnement stratégique québécoise en électricité) and local manufacturing.
Anticipate permitting and social acceptability requirements; early municipal and Indigenous partnership structuring is critical. Recent wind procurement models formalized municipal and Indigenous partnerships to enhance acceptance and benefit-sharing.
For hydro and transmission, plan on long lead times and staged approvals; align project critical paths to the 15-year plan cycles.

What this means for industry and large energy users (mining, metals, battery value chain, data centres, manufacturers, services)

Capacity access and sequencing:
- Confirmation that Québec aims to maintain and deepen its strategic advantage linked to the reliable generation of clean and affordable electricity for businesses operating in Québec. This reinforces the confidence that the electricity-based hypotheses behind any long-term investment by private parties in Québec are reliable, which is especially important in the context of growing regulatory tools aimed at promoting low-carbon production and penalizing high-carbon production entering a territory (for instance, in Europe).
- Energy availability and peak management are central; electrification will be prioritized where it yields the highest system value, while transitional roles for gas and renewable gases persist to manage winter peaks and hard‑to‑electrify loads.
- Tariff evolution under the Régie de l’énergie may differentiate by use and sector to reflect marginal costs and policy priorities (that is, examples already filed for data centres and blockchain uses).
Efficiency first:
- Electric efficiency of about 50 TWh by 2050 and targeted gas efficiency reduce connection sizes, mitigate peak charges, and can accelerate connection timelines.
- Actions: ISO 50001 adoption, advanced controls, waste‑heat recovery, participation in demand response and bi‑energy options; evaluate thermic networks in campuses and industrial parks. The plan highlights thermic networks as strategic assets to reduce electric peak and valorize local heat.
Fuel-switching and low‑carbon fuels: Growth in bioenergy and hydrogen creates alternatives for high‑temperature heat, off‑grid or remote operations, and heavy transport, with progressive greening of the gas mix through RNG.
Reliability planning: Peak constraints are material (additional coverage up to 22 GW by 2050), pointing to on‑site storage, behind‑the‑meter generation, and flexible operations as competitive necessities.
Long-term needs: the announced investment cycle visibility and scale allow manufacturers to rely on energy-related long-term needs in Québec to plan investments in Québec (such as plant opening, or upscaling production).

Practical takeaways for large energy users

Map expansion plans against Hydro‑Québec’s supply and transport plan milestones; secure capacity reservations early.
Explore long‑term offtake with independent power producers for renewable electricity (Power Purchase Agreement, or PPA) and RNG.
Integrate social acceptance and community benefits into site development to streamline permitting.

What this means for construction contractors

Coherence with precedent announcements: Québec’s PGIRE confirms a clear signal that major long-term infrastructure investments, and therefore construction needs, are upcoming. This justifies investments in developing relevant construction skills in various energy-related fields (notably, wind, solar, hydro, transmission and distribution, industrial plants).
Red tape and streamlining: legislative and regulatory changes will be considered to tackle the long delays observed in projects realization.
Reinforcement of made-in-Québec supply chains: the desire to develop industrial capacities in Québec to respond to diversified needs as anticipated with the project pipelines creates an opportunity to grow local procurement, and therefore, a more reliable, resilient and reactive supply chain.

Setting the GPS for CIRO’s annual priorities

Wed, 08 Jul 2026 00:00:00 Z

The Canadian Investment Regulatory Organization (CIRO) has published its 2027 Annual Priorities, emphasizing completion of integration initiatives and continued advancement of its broader strategic objectives.

Key priorities include:

finalizing a harmonized rulebook for investment dealers and mutual fund dealers;
completing CE harmonization;
advancing adviser compensation reforms by consulting on and finalizing rule amendments relating to an incorporated adviser compensation option to submit to the Canadian Securities Administrators (CSA) for review and approval; and
addressing the future of dual registration.

CIRO will review complaint-handling timelines, engage with the CSA in enhanced anti-fraud initiatives, conduct investor research (including behavioural “speed bump” interventions), consider improvements to account transfers, and provide additional structured and practical guidance on the Client-Focused Reforms.

Other CIRO priorities focus on regulatory evolution, such as operational efficiency and innovation testing through InnovateSafe, cyber resilience, access to on-line advice, registration and proficiency and greater transparency of CIRO’s market regulation function through an annual report. Finally, CIRO intends to review the Universal Market Integrity Rules with a view to potential modifications in order to better support smaller dealers and junior issuers.

Not just a learner’s permit: CIRO’s proposed changes to continuing education requirements

The Canadian Investment Regulatory Organization (CIRO) has issued a Request for comments– Proposal to harmonize CIRO Continuing Education Programs – Phase 2 where CIRO proposes to fully align CE requirements across Investment Dealers and Mutual Fund Dealers, including mutual fund dealers in Québec, under a single, principles‑based framework.

Key proposed changes include:

standardized CE hours;
harmonized compliance and professional development requirements;
elimination of carry‑forward and legacy exemptions;
expanded CE coverage to apply to certain executives;
consistent proration and leave‑of‑absence relief; and
the introduction of automatic suspension for CE non‑compliance.

One particular proposed amendment will have a significant impact on mutual fund dealers: CIRO proposes to align all dealers to a calendar‑year CE cycle and extend post‑cycle reporting to 30 days (from the current 10 business days). As part of the transition, CIRO proposes to add an extra month in the first cycle to provide mutual fund dealing representatives more time to complete the CE requirements in that cycle.

Comments are due July 15, 2026, with final rules expected in 2027 and a proposed effective date of January 1, 2028.

Pre-trip inspection: Updated CIRO staff notice on use of business, style or trade names

Earlier in June, the Canadian Investment Regulatory Organization (CIRO) amended its Mutual Fund Staff Notice MSN-0032 MFDA 1.1.7 – Use of Business, Style or Trade Names by Members or Approved Persons to delete the requirement for mutual fund dealers to notify CIRO separately of changes to trade, business or style names. CIRO staff now have direct access to trade name information for dealers and their Approved Persons on the National Registration Database, so separate notifications are no longer required.

Looking down the road: The CSA proposes amendments to the issuer bid, take-over bid and early warning reporting regimes

Wed, 08 Jul 2026 00:00:00 Z

On May 14, 2026, the Canadian Securities Administrators (CSA) proposed changes to a number of rules to provide issuers with greater flexibility to repurchase their own securities, enhance transparency of ownership of derivative interests in specified circumstances and enhance the integrity of the issuer bid, take-over bid and early warning reporting regimes. These changes are intended to reduce regulatory burden by introducing clarifying amendments and supplemental policy guidance. Below is what advisers need to know from an investment management perspective.

For eligible institutional investors (EIIs) currently using the alternative monthly reporting (AMR) system, the proposal clarifies that reporting is triggered when the investor crosses fixed thresholds of 10 per cent, 12.5 per cent, 15 per cent, 17.5 per cent, and so on. The CSA note that certain market participants had a practice of calculating the 2.5 per cent threshold against the EII’s previously reported position, as opposed to against these specified fixed thresholds. Advisers relying on the AMR should ensure that their monitoring systems are calibrated to those fixed thresholds. For EIIs that are not currently reporting under the AMR, including ones previously disqualified because of a formal bid, business combination or proxy solicitation, they can enter or re-enter the AMR system by issuing a news release and then filing the required report in the circumstances set out in the proposals.

Significant changes are also proposed to the early warning report (EWR) system. For example, the amendments would treat securities already held when an issuer becomes a reporting issuer as having been “acquired” at that time for early warning purposes. This means that if an adviser, fund or managed account already owns or controls 10% or more of a class of shares when that issuer becomes a reporting issuer, an EWR would generally be required to be filed. The CSA also clarifies in this specific deemed-acquisition scenario, the news release and moratorium provisions do not apply. Additional disclosures are proposed in the context of take-over bids and certain proxy solicitations with respect to bidders’ and soliciting securityholders’ aggregate economic positions (i.e., to include economic interests in related financial instruments and other agreements that have the effect of altering economic exposure to an issuer).

The CSA has also proposed new guidance in National Policy 62-203 Take-Over Bids and Issuer Bids to clarify that it expects EWR disclosure as soon as there is a “change in plans or future intentions or if the acquiror or any joint actor has taken irrevocable steps to effect a potential transaction”. The CSA is concerned about the use of boilerplate language to avoid filing updated EWR disclosure where there have been particular changes to the acquiror’s intentions. The notice indicates that significant steps by an acquiror (or joint actor) with respect to a particular transaction may, taken together, constitute a change in plans or future intentions, as described in the most recent EWR.

If the amendments move forward, some registrants may need to amend their policies and procedures to reflect the changes.

Comments on the proposal are due on August 12, 2026.

The authors would like to thank Ray Zhao, student-at-law, for his contributions to this insight.

Navigating a complaint from the College of Veterinarians of Ontario (CVO): A practical guide for veterinarians

Tue, 07 Jul 2026 00:00:00 Z

From time to time, a veterinarian may receive notification of a complaint from the College of Veterinarians of Ontario (CVO) on behalf of a client. Under the Veterinarians Act (Act), the CVO is responsible for receiving, investigating, and acting on complaints made against veterinarians, whether they practise in a veterinary clinic, mobile practice, or provide care for farm animals.

For a veterinarian, receiving a complaint can be stressful, but a high-level overview of the process can help make the complaint easier to navigate.

Overview of the complaint process: Five stages

When a complaint is filed, it will move through five stages:

The filing of the complaint, initial review, and issuance of a confirmation letter;
The Mediated Resolutions Program (MRP) window, if applicable;
The veterinarian’s written response;
The Complaints Committee (Committee) review and decision; and
Possible next steps, including a discipline hearing and a Health Professions Appeal and Review Board review.

The process may take anywhere from two to three years.

1. Complaints must be filed with the CVO; if verified, both parties will receive a letter of confirmation

The process usually starts with the complainant submitting a letter to the CVO. The College’s Registrar then conducts an initial review to determine if there is any merit to the complaint or whether it should be disregarded immediately.

If the complaint is not vexatious or inappropriate, the veterinarian and the complainant will receive a letter of confirmation.

2. A complaint may be selected for the Mediated Resolutions Program, but both parties must consent

Certain complaints may be flagged by the Registrar as suitable for MRP, which allows the parties to reach a resolution with an independent facilitator. While it is not appropriate for all complaints, MRP offers a consensual and low-cost process.

Both parties must agree to participate, and the CVO assumes all costs associated with the mediation. All complaints resolved through MRP must also be approved by the Committee.

Complaints involving the misuse of drugs, fraud, animal abuse, misrepresentation, sexual impropriety, or falsification of records do not qualify for MRP.

The possible outcomes of the MRP process are:

A letter of acknowledgement;
Policy changes in a facility;
An agreement to undertake further education; or
An apology to the affected party.

3. The veterinarian must provide a written response

If MRP is not undertaken, the veterinarian is required to submit a written response to the complaint.

Under the Act, a veterinarian has at least two weeks from the time they are notified to submit a written explanation to the Committee. As part of the investigation, a veterinarian is generally required to provide additional documents, such as medical records or witness statements.

After the veterinarian has responded, the complainant may comment on the response if they choose to do so. That comment will also form part of the investigation record.

4. Once the investigation is finalized, a panel will examine the written record of the complaint and make a decision

A panel of ten members of the Committee (nine veterinarians and one member of the public) will review the complaint and make a decision. The panel must make reasonable efforts to examine all written records and documents relating to the complaint.

The veterinarian and the complainant receive a copy of the decision. The possible outcomes are:

No further action: If the Committee has no or low concerns about the veterinarian’s conduct, the case is closed, subject to an appeal.
Recommendation or remediation: If the Committee identifies a low-to-moderate risk, it may provide recommendations to the veterinarian, or require that they undertake additional education or training. If the veterinarian cannot fulfil the undertaking, the case will be referred to the Executive Committee of the CVO. Appeals may also be possible.
Discipline hearing: If the Committee identifies a serious concern, it may refer the veterinarian to the Discipline Committee for an oral hearing.

Note that the Committee cannot order that the veterinarian pay damages or compensation to the complainant.

5. Possible next steps

a. A discipline hearing

If the complaint is referred to the Discipline Committee for a hearing, a panel made up of three to five members, including one member of the public, will review the veterinarian’s conduct and determine whether they are guilty of professional misconduct.

The hearing process involves the review and admission of written and documentary evidence, oral evidence, and expert reports.

If the veterinarian is found guilty, the Discipline Committee may order :

The revocation of their licence;
The withdrawal of their specialist recognition;
The suspension of their licence;
The imposition of a condition, limitation, or fine.

b. A review by the Health Professions Appeal and Review Board

If a party is dissatisfied with certain written decisions of the Committee, they may appeal to the Health Professions Appeal and Review Board (the Board). The appeal must be made within 30 days of the Committee’s written decision. The Board may consider whether the Committee’s decision was reasonable, and whether the investigation was adequate in the circumstances.

Importantly, this review is not a completely new hearing and does not involve retrying the complaint from the beginning. Instead, the Board reviews the record before it to assess the adequacy of the Committee’s process and the reasonableness of its outcome. Depending on the circumstances, the Board may confirm the Committee’s decision, send the matter back to the Committee for further consideration, or direct that further investigation be undertaken.

For a veterinarian, this review process can be an important safeguard where there are concerns about the fairness, thoroughness, or outcome of the complaints process.

IESO’s Long-Term 2 RFP – Window 2: Key developments and emerging issues

Tue, 30 Jun 2026 00:00:00 Z

The Independent Electricity System Operator (IESO) is shaking up the requirements under Window 2 of its Long-Term 2 (LT2) Request for Proposals. Recent engagement sessions signal several important developments for proponents, including expanded eligibility for repowered facilities, potential increases to proposal fees, the possibility for domestic content commitments, and being required to be in “good standing.”

While subject to change, the IESO expects to publish draft RFPs and contracts in July 2026, with proposal submissions due in Q2/Q3 2027 and contract awards expected in Q1 2028.

Two paths to eligibility for repowered facilities

Repowering projects that maintain or reduce their nameplate capacity will be deemed deliverable and will not be subject to deliverability testing, creating a clear competitive advantage. By contrast, projects that increase capacity must undergo deliverability testing. Supporting this approach, the IESO has adopted a broad, flexible definition of repowering, with no prescriptive equipment replacement criteria, relying instead on existing contract obligations, independent engineer certification, and potential adjustments to performance security as the guardrails.

The IESO is proposing two eligibility pathways for facilities with a nameplate capacity >1 MW. The first for existing Medium-Term Contract holders which are also required to have previously completed a 20-year (or multiple contracts totalling 20 years) IESO/OPA/OEFC contract and have completed at least 3 years of their Medium-Term Contract as of May 1, 2032; and the second for legacy facilities that do not currently have a Medium-Term Contract but have been in service for a minimum of 23 years as of May 1, 2032.

For repowering proponents, the key decision will be whether to operate for 3-years with merchant revenue or 3-years under an MT Contract.

Domestic content requirements

The IESO is expecting the inclusion of domestic content requirements for Window 2, broadly aligned with the Long Lead Time (LLT) RFP approach. Proponents would be required to submit a supply chain disclosure plan describing sourcing strategies, including the origin of goods and services and justification for any non-Canadian inputs. While this disclosure is primarily intended for informational and policy development purposes, proponents may elect to make binding commitments regarding Canadian content. In line with the LLT framework, such commitments would entitle proponents to a pricing advantage in the evaluation process.

Under the LLT, where a proponent opts to commit to Canadian content, a minimum threshold (e.g., 60 per cent of capital costs) is required to receive an evaluation incentive in the form of a reduction to the evaluated proposal price. However, these commitments would be enforceable: proponents would need to attest to compliance at commercial operation, and failure to achieve the committed level of Canadian content could result in liquidated damages of up to $5 million.

Proponents should obtain legal advice around the potential trade law implications of these new requirements, and how that would impact any particular project or proposal.

Increased proposal fees

The IESO has recently applied to the Ontario Energy Board to increase the maximum proposal submission fees for Window 2 to $25,000 from the current maximum fee of $10,000.

Although it is reasonable to rely on an Ontario Energy Board decision with respect to the rate, there are no generator representatives that are intervening in the IESO’s application so it is unclear how thoroughly this proposal will be tested.

E-PPA Design: DA to RT adjustments

The IESO is considering removing the Day-Ahead to Real-Time Adjustment (DARTA) mechanism for Window 2. DARTA was originally implemented in May 2024 as an interim measure to protect proponents from settlement risk arising from differences between day‑ahead (DA) and real‑time (RT) market prices. The IESO’s position is that by Window 2’s proposal submission deadline, proponents will have access to over 2 years of DA and RT pricing data and market participants are best positioned to manage uncertainty related to next-day production.

Removing the DARTA mechanism would shift significant, unmitigated DA to RT risk onto participants (potentially causing less participation in the procurement), despite no material change in the underlying forecasting uncertainty. This is particularly acute for weather-dependent resources, which remain exposed to uncontrollable variability with limited ability to hedge or manage the risk.

Locational rated criteria

The IESO is considering refinements to the locational rated criteria approach used in Window 1, where projects located in Northern Ontario received evaluation advantages and utilized approximately 1053.55 MW out of 1,115.10 MW of contract capacity in the energy stream and 190 MW out of 640 MW of contract capacity in the capacity stream. For Window 2, the IESO is exploring options to enable additional capacity in Northern Ontario and may expand locational incentives more broadly to encourage development in areas that provide identifiable system benefits, such as locations with available transmission capacity or those that support system reliability and defer infrastructure investments.

It remains to be seen whether additional locational criteria will drive procurements toward a more location-focused approach, to avoid projects being proposed in areas where they are unlikely to proceed.

Barring proponents not in good standing

The IESO is considering introducing exclusion criteria that would bar proponents from participating in procurements if they are deemed not to be in good standing, including where their conduct is considered inconsistent with good faith during prior procurement processes. This restriction could extend to affiliated entities and may result in a prohibition on participation in future procurements for three years or more. The IESO is still developing the specific criteria for determining good standing but has indicated that failure to execute an awarded contract may be one example of disqualifying conduct.

This type of proposal should be of concern to all participants in IESO procurements. It is ultimately a discretionary right granted to the IESO to determine whether or not a proponent is or is not “in good standing”. The first example cited by the IESO is particularly concerning, as the RFP for Window 1 expressly contemplated a proponent not executing an awarded contract (and a financial consequence followed). The proponents in question were operating within the four corners of the RFP process.

Which leads one to ask - what else can the IESO deem as “not in good standing”? Would a bona fide dispute under an existing PPA be sufficient (we don’t agree with you on this dispute)? What about a bona fide dispute under the IESO Market Rules? What about an OEB challenge of an IESO Market Rule amendment?

What is to prevent the IESO from simply using this new power to increase their leverage in any circumstances where they are adverse to a particular proponent in the future? As currently proposed – absolutely nothing.

Transparency & information disclosure

The IESO is considering enhanced transparency measures for Window 2, particularly in relation to the treatment of unsuccessful proposals. However, stakeholder feedback has been mixed, with some supporting greater disclosure (i.e., anonymized information on technology mix, project size), and others raising concerns about the impact on competitive tension and the potential exposure of proprietary strategies.

Recognizing the current feedback, the IESO is evaluating the release of additional post‑procurement information, such as lists of unsuccessful proposals, data on project characteristics, and reasons for non‑selection, while maintaining confidentiality over commercially sensitive details like pricing and specific project locations.

Proponents may be better informed for future submissions should the IESO elect to proceed with this mandate. However, proponents may also see key competitive details associated with their proposals put into the public domain – perhaps making them less competitive for the next window.

Communication/announcement reporting

Reflecting a potential increase in oversight and coordination around project communications, Suppliers awarded contracts under Window 2 may be subject to expanded reporting obligations. These expanded obligations would build on the existing requirements found in Window 1 (i.e., to provide quarterly progress reports from contract start to commercial operation) and require Suppliers to report on planned public communications relating to their projects, with the understanding that such information will be shared with the Ministry of Energy and Mines.

Open policy items

The IESO has identified several unresolved policy issues that may materially affect project viability and is continuing to engage with government on these matters, particularly in relation to siting and permitting constraints. In future procurement windows, repowering may be constrained where existing project sites are located in Prime Agricultural Areas. In addition, requirements to demonstrate consideration of alternative sites may not be practical for repowering projects, given that such facilities are inherently tied to fixed, existing locations. Finally, the IESO has indicated that all proposals, including those for repowering projects, are expected to remain subject to the mandatory municipal support requirement. These requirements largely come from the ministerial direction dated April 16, 2026; thus, an updated ministerial direction may be required to address these issues.

Next steps

The IESO has requested feedback on its latest engagement session by July 3, 2026; the feedback form is posted on the IESO’s website. The IESO’s next engagement session regarding Window 2 is expected to take place in August.

BLG’s Energy group provides expert guidance to clients navigating the IESO’s procurements, including the LT2 RFP. If you want to learn more about the LT2 RFP or how IESO procurements may affect your organization, please contact any of the key contacts below.

Canada’s Protecting Privacy and Consumer Data Act (Bill C-36): BLG’s guide

Mon, 29 Jun 2026 00:00:00 Z

On June 15, 2026, the federal government introduced Bill C-36, An Act to enact the Protecting Privacy and Consumer Data Act (PPCDA). If enacted, this long‑awaited legislation would mark the most significant reform of Canada's federal private-sector privacy regime in more than two decades.

Most critically, the PPCDA would replace the privacy provisions found in the Personal Information Protection and Electronic Documents Act (PIPEDA) with a modernized and strengthened framework, introducing new individual rights, new consent rules, a new enforcement regime and a new privacy regulator for private-sector obligations: the Data Protection Commission of Canada.

The PPCDA reflects the federal government's broader digital policy agenda, complementing the AI for All national strategy and the Safe Social Media Act (Bill C-34). BLG prepared this guide to explain the proposed PPCDA, help organizations understand what may be coming, and offer comparative insights with PIPEDA, Québec's Private Sector Act and the GDPR; our handy table highlights key differences between Bill C-36 and the Private Sector Act.

This guide will be updated as Bill C-36 progresses through the legislative process.

What the guide covers

Enforcement: the proposed Digital Safety and Data Protection Commission, administrative penalties of up to $10 million or 3 per cent of global revenue, and fines of up to $25 million or 5 per cent for indictable offences;
Accountability and governance: proposed obligations for privacy management programs, the role of the privacy officer, and record-keeping requirements;
Consent: proposed new consent exceptions and validity requirements;
New individual rights: the proposed right to disposal, data mobility, and the right to explanation of automated decisions;
Children: new heightened standards for children’s personal information;
Artificial intelligence: proposed rules for de-identification, anonymization, and transparency requirements for automated decision systems;
Outsourcing and cross-border transfers: new obligations directly imposed on service providers and PIA requirement for cross-border transfers;
Safeguards and incident response; and
Retention and disposal.

The authors would like to thank Marianne Bellavance, articling student, for her contributions to the guide.

From buybacks to enhanced disclosure: Canadian Securities Administrators signal a shift in regulation

Mon, 29 Jun 2026 00:00:00 Z

Sweeping changes have been proposed to Canadian securities law that would allow selective buybacks, enhance disclosure requirements, update the early warning system, and amend exemptions from takeover bid and issuer bid regimes (collectively, the Proposed Amendments). This development marks a shift by the Canadian Securities Administrators (CSA) towards providing issuers with greater flexibility, improving transparency, reducing regulatory burden, and enhancing the integrity of the issuer bid, takeover bid, and early warning reporting regimes.

Key takeaways

The CSA propose to introduce a selective repurchase exemption allowing issuers to repurchase up to 5 per cent of their own securities over a 12-month period, provided that certain conditions are met.
Enhanced disclosure of equity equivalent derivatives in takeover bids and proxy solicitations is proposed, with new requirements for both bidders and soliciting securityholders.
The CSA plan to update the early warning reporting regime with guidance focused on acquirors’ disclosure of future intentions, and clarification as to reporting triggers and deemed joint actorship.
Several amendments to exemptions from takeover bid and issuer bid regimes are introduced, such as the expansion of the non-reporting issuer exemptions. This amendment codifies that certain securityholders, in similar positions to employees, be excluded from the calculation of the existing exemption, where non-reporting issuers are exempt from the takeover bid and issuer bid regimes if they have 50 or fewer securityholders, excluding employees.

New selective repurchase exemption

The CSA have proposed an exemption from the issuer bid rules that permits issuers to repurchase up to 5 per cent of a class’s outstanding securities within a 12-month period, subject to certain conditions.

The current issuer bid regime does not allow issuers to repurchase shares through bilateral private agreements. Instead, issuers can only repurchase securities through a formal issuer bid made to all securityholders, or through one of the limited exemptions, such as the normal course issuer bid exemption conducted through a stock exchange.

Stakeholders have expressed concern that this regime is overly restrictive, noting that the inability to selectively repurchase securities may prompt market disposition by blockholders, which can artificially depress the market price of securities to the detriment of securityholders. Stakeholders have also noted that these limitations may deter investment, given that blockholders have fewer liquidity options in Canada compared to other jurisdictions, and in particular the United States.

As a result, the proposed exemption could significantly strengthen the Canadian issuer bid regime by providing issuers with the flexibility to undertake selective repurchases where it is in their best interest, and to improve the competitiveness of Canadian capital markets by reducing restrictions.

The following conditions must be met to utilize the exemption:

Purchaser and transaction limits: Issuers are limited to repurchasing securities from a maximum of 5 persons, in a maximum of 5 transactions, during a 12-month period.
Discount requirement: The consideration paid for the securities acquired, including brokerage fees or commissions, is less than the closing price of the class of securities on its principal market at the date of the bid. This condition should discourage shareholder activists from relying upon the proposed exemption to effect “greenmail” schemes.
Liquid market requirements: There is a liquid market in the class of securities at the date of the bid. The issuer’s board of directors is also required to determine that, upon completion of the bid, the market for the class of securities subject to the bid would not reasonably be expected to be materially less liquid than it was prior to the bid, and that the bid would not reasonably be expected to have a significant negative effect on the market price or value of the class.
Disclosure requirement: The issuer issues and files a news release that discloses the transaction and the number or principal amount of securities acquired during the preceding 12-month period. This disclosure must be made after the bid and before trading opens on the principal market for that class of securities.

This exemption would not reduce the number of securities an issuer could acquire through the normal course issuer bid exemption. The CSA plan to engage with the designated exchanges on potential amendments to their rules related to normal course issuer bids.

Enhanced disclosure of equity equivalent derivatives

The CSA have also proposed enhanced disclosure requirements that aim to improve the quality of disclosure provided for equity equivalent derivatives that alter an investor’s economic exposure to an issuer, particularly in the context of takeover bids and proxy solicitations requiring an information circular. The proposal is also intended to strengthen confidence in capital markets by promoting balanced and transparent disclosure. The amendments include specific requirements for both bidders and soliciting securityholders.

For bidders, the requirements include:

Takeover bid circular disclosures: A takeover bid circular must disclose any interests of the offeror or any person acting jointly or in concert with the offeror (joint actors) in related financial instruments involving the offeree issuer’s voting or equity securities, or in any agreement, arrangement, or understanding that alters the economic exposure of the offeror or its joint actors, with a six-month lookback period.
News release disclosures: During the bid, an offeror must issue and file a news release before the opening of trading on the next business day if it acquires, disposes of, or changes its interests in related financial instruments, or enters, amends, or terminates related arrangements.
Counterparty relationship disclosures: An offeror is required to disclose any relationship it, or its joint actors, has with a counterparty, or any of its affiliates, that, to a reasonable person, could be perceived as affecting the counterparty’s decision to acquire, dispose of, or vote on the securities of the offeree issuer, or indicate that no such relationship exists.

For soliciting securityholders, the requirements include:

Deemed control over a security: During a proxy solicitation, an acquiror or its joint actor that is a counterparty to an equity equivalent derivative is deemed to have acquired and to have control over the security, which triggers early warning reporting.
Beneficial ownership disclosures: An information circular must disclose beneficial ownership of, or control over, voting securities of the company, interests in related financial instruments, and arrangements altering the person’s economic exposure. A person relying on the public broadcast, speech, or publication exemption to solicit proxies is required to disclose their beneficial ownership of, or control over, the company’s voting securities.

Early warning reporting amendments

The Proposed Amendments include updated guidance relating to the disclosure of plans or future intentions of an acquiror or its joint actor. The guidance clarifies that an acquiror should reassess the accuracy of its most recent early warning report (EWR) disclosure regarding its plans or future intentions every time that the requirement to file is triggered, and update the disclosure as soon as there is a change in its plans or future intentions, or if it has taken irrevocable or significant steps in connection with a potential transaction or event.

There are also several key amendments to the early warning system to be aware of:

Securities of a previously non-reporting issuer: The CSA have proposed to amend the EWR rules to require securityholders to file an EWR where they have beneficial ownership of, or control or direction over, 10 per cent or more of the outstanding voting or equity securities both before and after an issuer becomes a reporting issuer.

If adopted, this Proposed Amendment would mark a significant change to market practice, given that securityholders currently do not typically file EWRs in respect of unchanged holdings when the issuer becomes a reporting issuer, such as on an initial public offering, on the basis that they have not acquired any additional securities. The CSA have indicated that it does not believe that the initial disclosure of a securityholder’s position in filing statements, prospectuses, or information circulars is an adequate substitute for the disclosure required under the early warning requirements.

In addition, the CSA have noted that, without an initial EWR, there is no obligation to update the market with changes in material facts regarding their investment intentions, which could lead to securityholders avoiding disclosures.
Securities of joint actors: Under the Proposed Amendments, joint actors would be deemed to have acquired the issuer’s securities that are beneficially owned or controlled by other joint actors when they began acting jointly. The CSA clarified that this itself does not constitute a takeover bid in the absence of a subsequent acquisition by one or more of the joint actors. Instead, the deemed acquisition by joint actors would apply to the calculation of whether EWR obligations have been triggered.

The rationale for the Proposed Amendment is that joint actors collectively holding 10 per cent or more of outstanding voting or equity securities in a class can influence control. When the joint actors cease acting jointly, each person would be deemed to have disposed of those securities, again potentially triggering an EWR obligation.
Trigger for subsequent filings: The defined term “securityholding percentage” is proposed to be introduced to clarify that the obligation to file a subsequent EWR is triggered where there is a change of 2 per cent or more in the acquiror’s post-event percentage ownership compared to the percentage ownership reported in its most recent EWR. There is also a clarifying amendment to confirm that eligible institutional investors relying on the alternative monthly reporting (AMR) system are required to file an AMR each time they cross a fixed 2.5 per cent threshold above 10 per cent.
Entry or re-entry into the AMR system: An eligible institutional investor not filing under the AMR system is able to enter or re-enter the AMR system by promptly issuing and filing a news release stating that it is eligible and intends to file under the AMR system, and by subsequently filing an alternative monthly report.

Amending exemptions and codifying common discretionary exemptions

The Proposed Amendments also amend and codify a number of exemptions from the takeover bid and issuer bid regimes, such as:

Removing the 5 per cent market purchase exemption: This exemption currently exists within the takeover bid regime, allowing bidders to purchase up to 5 per cent of the securities in the market subject to the bid during its pendency. However, it has been criticized for having minimal value and the potential to be misused by bidders to prevent competing bids. In addition, the exemption is rarely used, and the CSA have, therefore, proposed removing it.
Expanding the non-reporting issuer exemptions: Existing exemptions from the takeover bid and issuer bid requirements apply to non-reporting issuers where they have 50 or fewer securityholders, excluding employees. In the past, regulators have granted relief to issuers despite not satisfying the 50-securityholder limit, where the issuer exceeds the limit by less than 5 securityholders after permitting certain categories of holders to be excluded from the calculation. The categories excluded from the calculation are holders considered to be in a similar position to an employee, such as officers, directors, contractors, consultants, and spouses of qualifying persons. The Proposed Amendments codify these additional categories.
Codifying the exemptive relief allowing Dutch auction issuer bids: The Proposed Amendments codify the exemptive relief previously granted allowing issuers to extend Dutch auction issuer bids without taking up all deposited securities first. As a result, securityholders who have tendered to the bid must wait until the expiry of the extension period before their securities are taken up. However, this exemption does not apply where the bid is not undersubscribed or where the market price of the securities exceeds the highest price offered.
Allowing proportionate tenders: Although some modified Dutch auction issuer bids have included proportionate tender options, it is currently not permissible without exemptive relief. The Proposed Amendments codify the exemptive relief facilitating issuer bids with the option for securityholders to maintain their proportionate interest in an issuer after a bid.
Expanding acquisitions of convertible securities during issuer bids: The exemption is expanded to allow issuers executing an issuer bid to repurchase, redeem, or acquire convertible securities subject to the bid.

Next steps

The Proposed Amendments represent a significant update to the issuer bid, takeover bid, and early warning reporting regimes. The comment period for the Proposed Amendments is open until Aug. 12, 2026. For further information, please see CSA Notice and Request for Comment Proposed Amendments and Changes to the Issuer Bid, Take-Over Bid and Beneficial Ownership Reporting Regimes (May 14, 2026).

The authors would like to thank Alisha Eljaji, summer student, for her contribution in writing this article.