What changed at Algonquin Citygate
From April through July 2026, EIA reports that Algonquin Citygate averaged 43 cents per MMBtu below Henry Hub. In EIA's history back to 1999, only the comparable 2020 period produced a larger discount. Appalachian trading hubs averaged 77 cents below Henry Hub, the second-widest discount for that period in the same history.
That result reverses the simplistic idea that Algonquin always carries a premium. Basis is the difference between a local trading point and a benchmark; it can widen positively or negatively as transportation, local demand, supply, and power burn change. A commercial contract may settle against a different index and include utility, supplier, capacity, and delivery charges, so the hub spread is not the customer's delivered rate.
Record Canadian imports met lower regional gas demand
EIA attributes the discount partly to record pipeline imports from Canada. New England imports averaged 0.4 Bcf/d from April through July, more than 2.5 times the same period in 2025. At the same time, total regional natural gas consumption fell 5% year over year.
Power-sector gas use was the largest reported demand shift. New England gas-fired generation fell 1.1 billion kWh, or 6%. Wind generation increased 0.7 billion kWh, or 59%, and solar increased 0.2 billion kWh, or 29%. KilowattLogic calculates that the combined 0.9 billion kWh wind-and-solar increase equaled about 82% of the gas-generation decline by magnitude. That comparison describes the generation mix; it does not prove a one-for-one causal substitution.
| Signal | Apr.–Jul. 2026 | How to use it |
|---|---|---|
| Algonquin vs. Henry Hub | -$0.43/MMBtu average | Historical shoulder-season basis |
| Canadian imports | 0.4 Bcf/d average | Regional supply-balance input |
| Gas generation | Down 1.1 BkWh | Power-burn context, not a rate |
What this does not say about winter
April through July is not the winter heating season. EIA's measured discount therefore should not be extended into a January or February basis forecast. Cold-weather heating demand, pipeline availability, LNG deliveries, Canadian flows, storage, generation outages, and the power mix can all change the regional balance.
The earlier version of this page included unsourced deterministic winter price examples. Those examples have been removed. Current procurement decisions should use the buyer's actual delivery point, meter profile, contract index, pass-through terms, and current executable supplier quotes.
Commercial buyer checklist
- Confirm the contract index: Identify whether commodity charges use Algonquin Citygate, another hub, a utility index, or a fixed supplier component.
- Separate basis from delivered cost: Reconcile commodity, transportation, balancing, capacity, utility delivery, taxes, and supplier margin.
- Stress-test the right season: Use this EIA result as historical shoulder-season evidence, then run winter scenarios with current market inputs.
- Match hedges to operations: Compare fixed, index, and layered structures against the facility's load flexibility and budget tolerance; no structure removes every cost risk.
Buyer boundary
The EIA series is useful evidence for how New England basis behaved in a specific four-month period. It is not a live quote, a guaranteed hedge result, or a reason to ignore winter exposure. Compare it with current storage, weather, ISO-NE operations, and supplier terms before acting.