An Integrated Canadian Electricity Grid
Canada’s electricity grids are often better connected to the United States than to neighbouring provinces, leaving enormous opportunities for cooperation untapped. Dr. Madeleine McPherson, Associate Professor at the University of Victoria and a 2027 Clean50 and Clean16 honouree, argues that a more integrated national grid could lower electricity costs, improve reliability and strengthen Canada’s energy security. Drawing on her research and experience co-founding the Energy Modelling Hub, which developed Canada’s first open-source integrated energy modelling platform, McPherson highlights the economic and environmental benefits of stronger interprovincial connections. She points to modelling showing that expanded interties could substantially reduce electricity shortages during extreme weather, while identifying the institutional barriers holding projects back. McPherson outlines a path forward through coordinated national planning, improved electricity trading arrangements and fair cost-sharing frameworks, making the case for cooperation that respects provincial responsibilities and Indigenous rights while supporting Canada’s electrification ambitions.
Grid integration can help Canada decarbonize its power system and electrify its economy while keeping electricity affordable and reliable. Connecting provincial grids allows us to make better use of complementary resources, share backup capacity, and deliver clean electricity where it is needed. The challenge is to create institutions that turn these collective advantages into investments provincial governments, utilities, Indigenous Nations, and consumers can support. Canada now has an opportunity to replace decades of fragmented planning with a durable framework for cooperation [1].
The economic stakes extend well beyond electricity. Powering Canada’s Growth, published by New Economy Canada and the Canadian Chamber of Commerce, estimates that doubling electricity supply alongside accelerated electrification could add approximately $3 trillion in cumulative economic output relative to business as usual by 2050, and support 1.6 million additional jobs in that year. Its modelling estimates five dollars in economic benefits for every dollar invested in the power sector [2]. Grid integration is critical to realizing these benefits.
Yet our electricity connections often run more readily across the American border than between Canadian provinces. Trade with the United States provides valuable revenues, flexibility, and access to diverse resources. Limited domestic alternatives, however, leave provinces exposed to changes in American trade policy and market conditions. Strengthening east-west connections would give Canada more options when those relationships become uncertain. Domestic integration can complement existing American partnerships while improving our ability to meet Canadian needs through Canadian networks [1].
The persistent weakness of interprovincial connections reflects an institutional gap. Provincial utilities and system operators plan primarily for their own customers, within their own mandates. No enduring national process consistently identifies investments whose benefits cross those borders. A line can reduce costs across several provinces yet struggle to advance because the utility paying for it cannot recover enough of the wider benefit. Provincial decision-making can therefore produce chronic underinvestment in infrastructure that would benefit Canada collectively.
Commercial differences compound that problem. Most provinces rely on vertically integrated utilities, many publicly owned, while Alberta and Ontario operate different forms of competitive electricity markets. Their approaches to pricing, procurement, cost recovery, and risk differ. Canada has lacked a common planning process and an agreed framework for allocating intertie costs, alongside trading arrangements capable of connecting these structures. Without those foundations, each proposed link becomes a difficult negotiation over responsibilities and the distribution of benefits.
Above all, sustained political commitment has been missing. That is changing. In May 2026, Prime Minister Mark Carney announced the development of a National Electricity Strategy intended to double grid capacity by 2050, with connections between fragmented grids central to the agenda. At the June Energy and Mines Ministers’ Conference, governments identified five priority interties and supported a federal-provincial-territorial framework for regional planning, coordination, and standard cost allocation [3,4].
The July First Ministers’ statement added implementation milestones. Governments committed to completing intertie pre-development work by July 2027, getting an initial tranche underway by the end of 2027, and advancing all their respective projects by the end of 2028, subject to favourable market conditions. They also recognised that these objectives require full Indigenous engagement. These commitments create a political opening; making progress will require institutions that maintain cooperation beyond individual announcements and electoral cycles [5].
Our Atlantic modelling illustrates what that cooperation could achieve. Our analysis begins with provincial resource plans and translates their projected generation fleets and demand into a common model of hourly operation in 2050. It compares independent provincial operation with joint Atlantic dispatch, then tests increases in interprovincial transfer capacity. Generation capacity and demand remain fixed across these operational comparisons, allowing us to examine the effects of coordination and transmission separately from changes in provincial investment plans [6].
Joint dispatch reduces regional emissions and load shedding even with existing transmission capacity. Increasing transfer capacity produces further reductions in emissions and renewable curtailment, allowing more available clean generation to reach consumers. The analysis also finds less reliance on external imports and greater opportunities for exports. These capacity sensitivities demonstrate the value of stronger connections, although they do not establish the engineering design or investment case for particular transmission projects [6].
Our macroeconomic analysis adds another perspective. Its expanded-intertie scenarios use an electricity price path averaging approximately eight percent below the reference case by 2050. Interties alone produce little change in regional GDP, but when combined with an electrification package, they support Atlantic real GDP approximately 4.8 percent above the reference case by 2050 [7].
Extreme weather strengthens the case for evaluating interties across several dimensions. A recent Electricity Canada study examines future grids exposed to heat, drought, storms, wildfire, and other hazards. Generation investments are modelled with a capacity expansion model (COPPER), and resource adequacy is independently assessed with PRAS. This distinction matters: a system that satisfies a planning reserve margin can still experience substantial shortages when weather simultaneously affects electricity demand, generators, and transmission infrastructure [8].
Under the study’s extreme-weather assumptions, expanded interties reduce national loss of load expectation, the expected annual hours of supply shortfall, by approximately 69 percent. Provincial reductions reach 92 percent in British Columbia, 78 percent in Saskatchewan, and 90 percent in Ontario. These are modelled results demonstrate how access to neighbouring resources can reduce exposure to weather-related supply shortages [8].
How then can we reap the benefits of greater grid integration?
International experience points to two major institutional gaps Canada must address. The first is governance that combines planning from the provinces with coordination across the country. Europe’s transmission operators collaborate through ENTSO-E, while Australia’s AEMO coordinates planning across its interconnected eastern electricity system. These arrangements give someone explicit responsibility for examining benefits beyond individual jurisdictions, while maintaining local knowledge and priorities [9].
Canada needs that coordinating function, adapted to our federation. Provincial utilities and system operators must remain the foundation of planning and operation. A national institution should bring them together, reconcile assumptions, identify shared opportunities, and organise the analysis needed for investment decisions. Governments, regulators, and Indigenous Nations must help shape its mandate and procedures. Governance should establish how cooperation works and who is accountable before asking participants to trust the resulting national plan.
The second gap is a planning framework that supports allocation according to the beneficiary-pays principle. International practice distinguishes the assessment of a project’s value from the negotiation of who pays. A consistent cost-benefit assessment identifies which jurisdictions gain through lower costs, improved reliability, reduced emissions, or other outcomes. Cost allocation then uses that evidence to distribute financial responsibilities. This helps projects proceed when benefits extend beyond the province hosting the infrastructure [9].
Our forthcoming Canadian cost-benefits framework proposes a common core assessment of economic, environmental, reliability, and resilience benefits, supplemented by an extended assessment reflecting project-specific interests. The latter includes Indigenous rights and interests, national security, policy objectives, and health and wellbeing. Benefits should be evaluated with and without an intertie, over a sufficiently long horizon and across several scenarios. Tracking who benefits is essential, and overlapping measures must be handled carefully to avoid double counting [10].
This approach acknowledges that not every value can be reduced to dollars. Indigenous rights require meaningful involvement and respect independently of any calculated financial benefit. National security and community impacts also require judgement alongside quantitative evidence. A shared framework makes these considerations visible, provides comparable information, and clarifies uncertainties. It supports negotiations about cost sharing, ownership, and public funding without pretending that modelling can settle every political question.
A regional gain also does not guarantee a gain for every participant. Exporting provinces may invest in additional generation while importing provinces avoid construction costs. Electricity payments transfer money between those participants and must be distinguished from savings for the combined system. Agreements can distribute benefits through contracts, ownership shares, or cost contributions. Assessments must include transmission capital costs before drawing conclusions about net value or consumer bills. This is particularly relevant to the Atlantic dispatch study, which reports operating and fuel costs and excludes capital costs from its operational comparisons of future electricity systems.
The M3 platform provides analytical infrastructure for this work. Canada’s first open-source integrated energy modelling platform brings together data, models, and visualisation tools.
CODERS supplies common input data; COPPER examines investment pathways; SILVER assesses hourly operation; and PRAS evaluates resource adequacy. Energy-economy and agent-based models extend the assessment to technology adoption, economic activity, and labour markets. Together, these capabilities allow planners to examine multiple benefits across provinces using linked analytical workflows [11].
That breadth is especially useful for interties, whose value reaches beyond electricity production costs. Open data and models make assumptions available for scrutiny and enable others to reproduce and challenge results. Provincial experts remain essential for validating network representations and operating practices. M3 can support a shared evidence base for national planning while allowing utilities, regulators, researchers, and Indigenous partners to assess how alternative choices affect their systems and interests [10,11].
Canada now needs to establish three functions. First, national planning must stitch provincial plans together and apply a consistent cost-benefits framework. An initial planning council could convene existing utilities and system operators, supported by dedicated modelling capacity, and develop into a permanent agency. Its work should include shared scenarios, validation with provincial experts, transparent project comparisons, and regular revisions. Joint planning should assess transmission alongside generation, storage, demand flexibility, and efficiency so that interties serve wider system needs [1].
Second, Canada needs arrangements that enable electricity trading across provincial boundaries. These must accommodate vertically integrated utilities and competitive markets while working alongside existing American trading relationships. Bilateral contracts with negotiated prices provide a practical starting point. A Canadian trading framework could begin by facilitating bilateral transactions, coordinating transmission access, and clarifying scheduling and settlement. Provincial participants could add exchange-based mechanisms later if they demonstrate value. Neither an exchange nor its prices should be a prerequisite for new connections. The immediate task is to make trade workable and finance beneficial infrastructure through agreed cost sharing, utility rate bases, and federal contributions [1].
Third, regulatory harmonisation must make cooperation workable and provide a credible process for resolving disputes. Provincial regulators could collaborate through a national coordination forum to address transmission access, cost recovery, trading rules, and conflicting approval requirements. Its authority would need to be agreed with participating governments. Clear procedures for adjudicating disagreements would reduce the risk that investments stall after substantial planning work, while maintaining provincial responsibility for local systems and consumers [1].
These functions need not become three entirely separate organisations. Canada can test arrangements, refine mandates, and build permanent capacity as cooperation develops. What matters is that pan-Provincial planning, cross-border trading, and regulatory coordination each have a clear home. With provincial institutions as the foundation and Indigenous Nations involved from the outset, Canada can turn the current political commitment into an interconnected grid that supports electrification, strengthens energy security, and distributes the benefits of clean power more widely.
References
[1] McPherson, M. (2025). Powering the Federation: A Blueprint for National Electricity Integration in Canada. C.D. Howe Institute, Commentary No. 696. October 30.
[2] New Economy Canada and Canadian Chamber of Commerce. (2026). Powering Canada’s Growth: The Economic Case for an Electrified Canada. September
[3] Prime Minister of Canada. (2026). Prime Minister Carney announces forthcoming National Electricity Strategy. May 14. https://www.pm.gc.ca/en/news/news-releases/2026/05/14/prime-minister-carney-announces-forthcoming-national-electricity
[4] Natural Resources Canada. (2026). Canada takes action to advance a stronger grid and increase reliable, affordable energy. June 26. https://www.canada.ca/en/natural-resources-canada/news/2026/06/canada-takes-action-to-advance-a-stronger-grid-and-increase-reliable-affordable-energy.html
[5] Prime Minister of Canada. (2026). First Ministers’ Joint Statement. July 23. https://www.pm.gc.ca/en/news/statements/2026/07/23/first-ministers-joint-statement
[6] Saedi, Y., Seatle, M., Energy Modelling Hub and SESIT. (2026). Atlantic IRP Model Assumption and Results. September 22. Halifax, Canada
[7] Azevedo, D. (2026). Energy Modelling Hub and SESIT. (2026). Macroeconomic modelling results. September 22. Halifax, Canada
[8] Electricity Canada (2026). Building Grid Resilience through Interprovincial Interties. September 23
[9] McPherson, M. (2025). Best Practices for Grid Integration. 24th Wind and Solar Integration Workshop, Berlin, October 7–10.
[10] Lonergan, K. E., and McPherson, M. (2026). A Made-in-Canada Cost-Benefits Framework for Interjurisdictional Electricity Transmission: Starting the Conversation. Western Transmission Catalysts. Forthcoming;
[11] Energy Modelling Hub. M3 Modelling Platform and Open Models. Accessed October 7, 2026. https://m3.cme-emh.ca/ and https://m3.cme-emh.ca/open-models/
