Electricity rarely attracts the same trade-war attention as steel, automobiles or lumber, but a new study suggests putting tariffs on Canadian power could produce consequences that reach far beyond the border. Researchers at Cornell University found that making Canadian electricity more expensive could push up power-market prices in New York, increase reliance on fossil-fuel generation and leave the grid with less flexibility during extreme weather. The findings, published October 1, 2026 in Nature Communications, are based on a decade of electricity-market data and detailed simulations of the New York power system. Importantly, this is a warning about potential trade restrictions rather than evidence that a new electricity tariff is already appearing on household bills.
The Study Tests a Tariff Shock—Not a New Charge Already on Power Bills
The Cornell researchers examined what would happen if electricity delivered from Canada suddenly became more expensive because of either a U.S. import tariff or a Canadian export surcharge. Their model used New York Independent System Operator data covering 2015 through 2024, including roughly 165 million records from the state’s day-ahead electricity market. The researchers then simulated different tariff levels on electricity coming from Ontario alone and on power imported from both Ontario and Quebec. At the time the research was published, Cornell said electricity itself had so far avoided tariffs in the broader Canada-U.S. trade dispute, making the study primarily a test of what could happen if that changed.
The distinction matters because some of the numbers in the study represent stress scenarios, not existing government policy. Under the historical market conditions used in the model, Ontario electricity was nearly priced out of New York once a tariff reached roughly 55%. When tariffs covered both Ontario and Quebec, the threshold climbed to about 90%, reflecting the stronger price advantage of Quebec hydropower. Those figures should not be read as predictions that governments will impose tariffs of that size. The researchers also found effects at lower tariff levels as imports declined and marginal energy prices increased. The exact thresholds depend on variables such as natural-gas prices, electricity demand, renewable generation and the availability of alternative imports.
Canadian Power Is a Small National Share but a Major Regional Safety Valve
At the national level, Canada-U.S. electricity trade can look relatively modest beside the enormous oil and natural-gas relationship between the two countries. Regionally, however, the picture is very different. The Canada Energy Regulator says 86 international power lines connect the two countries. Canada exported 32.7 terawatt-hours of electricity to the United States in 2025 while importing 22.1 TWh in the other direction. Canada also accounted for 81.3% of the electricity imported by the United States that year. The flows can reverse as weather, hydroelectric production, demand and market prices change, making the border increasingly function like part of one interconnected energy system rather than two isolated grids.
New York shows why national averages can conceal that regional importance. From 2015 through 2024, Canadian electricity supplied an average of 9.89% of New York’s load, including 4.25% from Ontario and 5.64% from Quebec. During some five-minute periods, however, imports from the two provinces supplied as much as 45% of New York’s demand. Canadian imports exceeded 20% of total state load during 492 hours across the decade. Those periods were uncommon, but they illustrate why an import can have more reliability value than its annual market share suggests. A supply source that appears modest over 12 months can become much more important during a handful of unusually hot, cold or constrained hours.
Tariffs Push the Market Toward More Expensive Electricity
The basic price mechanism is straightforward. Canadian suppliers currently compete with generators inside New York and with electricity offered by other neighbouring markets. Adding a tariff makes affected Canadian bids more expensive. The Cornell simulations found that as tariffs increased, Canadian imports fell while New York’s marginal energy prices rose. The grid responded by dispatching more generation within New York and drawing additional electricity from neighbouring U.S. markets such as PJM and ISO New England. Those alternatives, however, could only partially replace the lost Canadian supply at comparable prices. The result in the model was higher electricity procurement costs and a negative overall economic-welfare effect.
That does not mean a 10% electricity tariff would automatically produce a 10% increase on a household’s monthly utility bill. The study primarily examines wholesale market clearing, marginal electricity prices and power-purchase costs rather than producing a single nationwide retail-bill forecast. Retail rates also contain transmission, distribution and other regulated costs. Earlier analysis by the Center for Strategic and International Studies similarly noted that a tariff’s effect on a retail bill would generally be smaller than the tariff rate because imported wholesale electricity represents only part of the total cost paid by customers. The clearest conclusion from the Cornell modelling is therefore directional: restricting competitively priced Canadian electricity places upward pressure on the cost of supplying power in the affected U.S. market.
Grid Risk Becomes More Serious When the System Is Already Under Stress
The reliability findings may be more significant than the average-price impact. Researchers simulated the 100 most severe summer peak-load days, concentrated mainly in July and August. As Canadian imports were reduced, New York had fewer reserves available and relied more heavily on local generation. In high-tariff and cutoff scenarios, the model increased the use of oil-fired peaking plants, particularly around transmission-constrained New York City and Long Island. These units can be valuable in emergencies, but they generally operate infrequently and carry higher operating costs than generators normally dispatched by the market. Imports from Quebec are especially useful because high-voltage connections can deliver electricity directly toward heavily populated downstate areas.
The researchers also recreated severe winter conditions using December 23, 2022, during Winter Storm Elliott, as a test case. They ran 200 Monte Carlo simulations at different gas-generator failure rates and compared full responsive Canadian support, fixed imports and a complete cutoff. With full Canadian support, the modeled failure level at which load shedding began increased from 40% to 55%. That does not mean Canadian power alone would prevent every blackout, but it indicates that imports can provide valuable operating room when domestic generators fail. The historical danger is real: FERC and NERC found that Winter Storm Elliott produced nearly 90,000 megawatts of simultaneous unplanned generation losses, while several grid operators were forced to shed firm customer load to maintain reliability.
Replacing Canadian Power Can Also Mean Burning More Fossil Fuel
The source of Canadian electricity matters almost as much as its price. Hydro-Québec says more than 99% of the electricity it generates annually comes from renewable sources, with massive hydroelectric reservoirs providing both energy and flexibility. Ontario’s system is different but also contains substantial low-carbon generation. Independent Electricity System Operator data show that nuclear plants supplied 48.2% of Ontario’s transmission-connected electricity output in 2025, while hydro contributed 23.1% and wind another 8.7%. Gas and oil generation accounted for 19.3%. That means reducing imports from Ontario and Quebec does not simply change where electricity is purchased; it can also change which fuels are used to replace it.
In the Cornell simulations, lost Canadian electricity was partly replaced with additional fossil-fuel generation in New York and neighbouring U.S. systems. Consequently, modeled carbon emissions and New York’s electricity-purchase costs both increased relative to the tariff-free case. That interaction is particularly relevant because New York’s Climate Leadership and Community Protection Act calls for 70% renewable electricity by 2030 and a zero-emission electricity sector by 2040. Cross-border hydropower is not the only tool available for achieving those targets, but reducing access to low-carbon imported electricity could force the system to find replacement energy, storage or generation elsewhere. The paper therefore treats electricity tariffs as both an economic and an emissions question rather than conventional customs policy alone.
Billions in New Transmission Have Raised the Stakes
The Canada-New York connection has also become more substantial because of new transmission infrastructure. The Champlain Hudson Power Express, a 1,250-megawatt transmission project connecting Quebec with the New York City area, reached commercial operation on May 13, 2026. NYSERDA says the line can supply up to 20% of New York City’s electricity demand with Canadian hydropower. The Cornell paper puts the project’s cost at roughly US$6 billion and notes that its financing and long-term contractual arrangements were developed around expectations of tariff-free electricity trade. That makes trade policy more than a short-term issue for hourly electricity prices; it also becomes part of the economics surrounding infrastructure expected to operate for decades.
The researchers argue that introducing new trade costs could therefore affect future investment decisions as well as current power markets. Long-distance transmission projects require large upfront investments and depend on assumptions about future power prices, congestion revenues and contracts. If governments begin treating cross-border electricity as a recurring tariff target, investors may assign greater policy risk to future connections. That does not mean individual projects would automatically become uneconomic, and the study does not model every proposed transmission line in North America. It does show why policy uncertainty matters differently for electricity than for many ordinary imported products: billions of dollars can be committed to infrastructure long before the electrons begin moving across the border.
The Biggest Caveat: This Is a New York Case Study, Not a Nationwide Bill Forecast
The study’s results are substantial, but its boundaries are just as important. Researchers modeled the New York electricity system using historical market conditions between 2015 and 2024. The 55% and 90% tariff thresholds reflect the natural-gas prices, electricity demand, generator availability, renewable output and transmission conditions that existed during that period. They should not be treated as universal thresholds for Michigan, Minnesota, New England or the entire United States. The paper itself says its framework may be applicable to other interconnected systems, rather than claiming that every region would experience identical price or reliability effects.
The broader significance is that electricity behaves differently from most products caught in a trade dispute. Supply and demand must remain balanced continuously, transmission capacity is limited, and electricity cannot simply sit at a border warehouse until a tariff disagreement ends. The Cornell results indicate that restricting Canadian supply would raise modeled New York market costs, shrink reserves and increase emissions, with the largest reliability consequences emerging during stressed conditions. How large those effects would be in practice would depend on the size and geographic scope of any future restriction, fuel prices, weather, available generation and alternative transmission routes. As of the study’s October 1 release, Cornell reported that electricity had so far remained outside the tariff fight—making the research a warning about a potential next step rather than a description of a tariff already in place.
