In mid-February, BTU Analytics recently discussed the impacts of President Trump’s executive order that paused offshore wind lease sales in federal waters and the issuance of approvals, loans, and permits for onshore and offshore wind projects. As Massachusetts, New York, and New Jersey are among the top 10 states for planned wind development, which now faces meaningful roadblocks in coming to fruition, BTU Analytics explores how the evolving New England demand landscape under the new administration could alter natural gas basis dynamics in the region.
The Northeast and Canada are the two main regions that supply New England. From the Northeast, most of the volumes flow on Algonquin Gas Transmission (AGT) and Tennessee Gas Pipeline (TGP), while volumes coming from Canada into New England arrive via Portland Natural Gas Transmission System (PNGTS) and Maritimes and Northeast Pipeline (Maritimes).
Domestically, flows into New England from the Northeast thus far this winter have been performing as usual, averaging 2.71 Bcf/d between November 2024 and January 2025, which is just 48 MMcf/d lower than last winter’s November–January average of 2.76 Bcf/d. However, due to the arctic blast in mid-January, Canadian imports into New England via PNGTS and Maritimes reached the highest level since February 2015, averaging a combined 0.61 Bcf/d for the month to feed winter demand.
As Canadian gas is the marginal molecule in New England, there is a strong relationship between Algonquin Citygate (ACG) basis, temperature, and the utilization of pipelines that bring in Canadian volumes (Maritimes and PNGTS). As seen in the figures below, as heating degree days (HDDs) increase and temperatures get colder, the utilization of Maritimes and PNGTS subsequently increases since additional volumes are needed to meet the rise in heating demand. As a result, ACG basis strengthens to strong premiums to bring increased volumes to the region. However, the relationship is imperfect, as there are other energy sources, such as coal plants, that provide support during peak demand events when pricing is supportive.
Despite New England’s historically high winter premiums, pricing dynamics may change in the coming future as regional demand evolves. Currently, demand in New England is primarily driven by residential/commercial (res/com) and power demand, with the former dominating the winter and the latter driving the summer. However, looking ahead, the power market could take on increased importance in New England.
Planned coal retirements could lead to increased winter basis premiums at ACG to incentivize increased Canadian imports into New England to meet peak demand. Conversely, increased offshore wind generation may reduce dependence on Canadian imports to meet peak demand, thus decreasing the magnitude of winter basis blowouts. However, as noted above, there is uncertainty around offshore wind due to President Trump’s executive order, placing downside risk on offshore wind growth, and ACG basis, beyond 2025. If both coal generation decreases and offshore wind fails to materialize, there is considerable upside risk to ACG basis, as a greater share of peak demand would need to be met by gas generation.
BTU Analytics expects ACG winter basis premiums to grow in 2028+ as coal retirements will offset offshore wind growth. However, until then, BTU Analytics expects ACG basis to remain consistent with historical patterns during peak demand, albeit at a lower level than the premiums seen this year. For more in-depth Insight into natural gas basis dynamics in New England, or any other key natural gas market, check out our comprehensive suite of energy market tools and analysis.
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