New England could build a natural gas pipeline with the money saved on electricity price spikes due to supply constraints during the recent cold spell

The recent three-week cold snap from January 18 to February 8, 2026, starkly exposed New England’s vulnerability to natural gas pipeline constraints. Wholesale locational marginal prices (LMPs) in ISO New England soared, with peaks exceeding $660/MWh on days like January 27 amid repeated grid alerts and emergency actions. Actual average LMPs during the period likely hovered around $180/MWh or higher, driven by Algonquin Citygate gas prices spiking dramatically due to constraints favoring home heating over power generation.

Had sufficient pipeline capacity enabled unrestricted access to low-cost Marcellus Shale gas, the outcome would have been dramatically different. Marcellus hub prices stayed far closer to national levels (around $8–$10/MMBtu during spikes), plus modest transportation (~$0.50/MMBtu), versus the constrained Algonquin surges. This ~$16–$18/MMBtu differential would have cut marginal costs for efficient gas plants (heat rate ~7.5 MMBtu/MWh) by $120–$135/MWh. With system energy use over the 22 days estimated at 9–10 million MWh (elevated winter loads of 400,000–450,000 MWh daily during peaks), wholesale market savings alone would have reached approximately $1.1–$1.2 billion. These avoided costs would reduce utility procurement expenses, potentially lowering retail bills for the region’s 6.5 million electric customers by an average of $170–$185 per account if fully passed through.

Additional savings stem from minimizing reliance on expensive, higher-emitting oil-fired generation. During peak cold periods (e.g., January 24–28), oil and dual-fuel units supplied up to 35–44% of power on high-demand days, with output nearing 8 GW as gas supplies tightened. Oil costs hit $250+/MWh (No. 2 fuel oil ~$3.80/gallon or $27/MMBtu, heat rate ~9.5 MMBtu/MWh). Displacing an estimated 1.5 million MWh of this with gas at ~$64/MWh yields roughly $290 million more in savings.

Environmental gains further enhance the picture. Switching from oil (0.68 metric tons CO₂/MWh) to gas (0.41 metric tons CO₂/MWh) avoids ~0.27 tons per MWh replaced, or ~405,000 metric tons total. Using the EPA’s social cost of carbon (~$190–$215 per metric ton for near-term emissions), this delivers ~$80–$90 million in societal climate benefits—excluding local air quality improvements from reduced SO₂ and particulates.

Total estimated benefits from unconstrained gas access: roughly $1.5–$1.6 billion ($1.1–$1.2 billion wholesale + $290 million oil avoidance + $85 million emissions social costs).

These figures align closely with broader analyses of pipeline economics. The revived Constitution Pipeline—a proposed 124–125-mile, 30-inch line from Pennsylvania to New York interconnects serving New England—has drawn renewed attention amid federal pushes. A recent S&P Global study estimates it could deliver up to $11.6 billion in total energy savings over 15 years ($8.5 billion net after costs) by curbing winter spikes and providing steady low-cost supply access, while supporting jobs and economic growth.

While exact costs for Constitution remain under update (original estimates were under $700 million, with delays inflating prior figures), similar Northeast projects suggest $5–$13 million per mile or higher due to terrain, regulations, and contingencies—potentially $1–$2 billion+ for a major line of this scale. Smaller expansions (e.g., compressor upgrades or segments adding hundreds of MMcf/d) cost hundreds of millions.

Remarkably, the modeled $1.5–$1.6 billion in benefits from just this single extreme cold snap could cover a significant portion—or potentially all—of the capital cost for a key new pipeline like Constitution or comparable capacity additions. Proponents note that avoiding even one major spike event over a pipeline’s life could justify its build, with recurring winters amplifying payback. Critics highlight permitting hurdles, environmental concerns, and alternatives like renewables or efficiency, but the math from this winter underscores the steep price of inaction: billions in extra costs, elevated emissions, and grid strain.

This cold snap—amid ongoing debates over projects like Constitution (targeting permits in 2026 and service by 2027)—highlights New England’s infrastructure gap. Pipeline limitations force costly LNG imports or oil backups during extremes, inflating prices and risks. Expanding capacity could deliver reliability, affordability, and emissions reductions, with this period’s savings demonstrating rapid potential payback. Policymakers must balance these tangible impacts against long-term decarbonization goals for truly sustainable, low-cost energy.

Looking ahead, long-term energy security and reliability in New England demand a pragmatic backbone of dispatchable, fuel-secure resources like natural gas and nuclear power. Reports from NERC and ISO-NE consistently warn of escalating winter risks from pipeline constraints, surging demand (driven by electrification and data centers), and retirements of firm capacity—issues this storm vividly confirmed.

Natural gas, already providing ~45–50% of the mix in normal conditions and essential for bridging peaks, offers abundant, flexible supply when pipelines are adequate. Nuclear plants like Millstone and Seabrook deliver steady, carbon-free baseload (~20% of generation during the event), with on-site fuel ensuring performance in extremes. Together, these reliable sources provide the firm foundation needed to integrate renewables without blackout risks, support affordability amid rising loads, and ensure resilience against weather volatility or supply disruptions—safeguarding the grid for decades to come.

https://open.substack.com/pub/stevethurston/p/new-england-could-bui...