Neel Somani breaks down the key factors behind East Coast power price spikes

If you live on the East Coast, you have probably opened a winter utility bill and wondered how your electricity costs could possibly be that high. Every few years, the story makes headlines: a cold snap hits the Northeast, power prices spike to hundreds of dollars, and politicians demand answers. But the real explanation rarely makes it past the financial trading desks and utility commission meetings where it actually gets discussed.

Neel Somani, a former quantitative researcher at Citadel who covered power markets, has spent time breaking down this problem. Having studied the mechanics of energy pricing across multiple regions, Somani offers a perspective shaped by both the economics of electricity market structure and the operational realities that make the East Coast uniquely vulnerable to these spikes.

The Generation Stack: Who Goes First

To understand why prices spike, you first need to understand how electricity is actually priced. It is not averaged or blended. The price of power at any given moment is set by the last, least-efficient unit of generation that must be turned on to meet total demand.

In New England, the grid operates a layered generation stack. At the bottom are the cheapest sources, renewables and nuclear, which run at near-zero marginal cost and go first. Then come natural gas generators, which vary in efficiency and cost. And then, at the very top of the stack, sit the oil generators: expensive, outdated, and almost never used.

“The first thing to know is that the price for power is based on the last megawatt of power that’s produced,” Somani explains. “In New England, you have renewables, you have a nuclear plant called Millstone, you have natural gas generators, and then you have oil generators. You almost never hear me talk about oil generators, because they’re so inefficient.”

That near-invisibility is by design. Oil-fired peaker plants are essentially emergency units, the equivalent of a backup generator in your basement that you never want to run. But in New England, they are relevant in ways they are not in other parts of the country, and understanding why brings us to the heart of the price spike problem.

The Winter Squeeze

New England sits at the end of a long, constrained natural gas pipeline network. The region does not produce its own gas. It imports it. And in winter, that pipeline capacity gets pulled in two directions at once.

“The winter is when things get interesting,” Somani notes. “In the winter in New England, natural gas has to be used to heat homes. If you don’t heat your home, your pipes can freeze, and that’s super expensive to fix. So people have some fixed amount of natural gas demand.”

This is the structural problem. Residential and commercial heating demand is relatively inelastic: people need to heat their homes regardless of price. When temperatures plunge, that demand becomes locked in, competing directly with the natural gas power plants’ need to generate electricity.

The result is predictable. There simply isn’t enough natural gas flowing through the pipelines to meet demand for heating and electricity generation simultaneously. When that constraint bites, grid operators have to reach higher up the generation stack. And that means turning on the oil units.

“There’s no longer enough natural gas to meet power demand,” Somani explains. “The way that’s handled in New England is you have to turn on some of the oil generators. I mentioned that price is set based on the least efficient unit of power, and that’s oil. And since that’s super expensive, which is one of the reasons power prices can rise significantly.”

This dynamic has played out repeatedly in recent years. During Winter Storm Fern in early 2026, New England real-time power prices spiked to between $400 and $700 per megawatt-hour. In January 2026, Massachusetts saw the highest natural gas price ever recorded in ISO-New England’s pricing database, which dates back to 2003. On January 27 of that year, wholesale electricity prices soared to $441.8 per megawatt-hour, compared with an average of $135.08 for the entire month of January 2025.

The Gas Price Feedback Loop

Here is where the economics become particularly pointed, and where Somani’s market background adds clarity that most reporting misses. It is not just that electricity prices rise when oil generators come online. Natural gas prices spike in lockstep, and the reason is rooted in basic incentive structures.

“Think about what happens if you’re a natural gas salesman in Algonquin, which is the natural gas hub in New England, you’re thinking that anyone you sell natural gas to is probably making a lot of money, because they can put it in a natural gas generator and get paid the oil price while only paying the natural gas price.”

The logic is airtight. If power generators can sell electricity at the oil-set price while burning natural gas, the margin is enormous. A rational gas seller will recognize this and raise the asking price for gas until that arbitrage disappears. They will keep raising it until the economics of generating power from natural gas and generating power from oil are roughly equivalent.

“It’s in your interest to keep raising the natural gas price until it’s basically the same cost to produce a megawatt of power from a natural gas unit as it is from an oil unit,” Somani says. “So the natural gas price also shoots up. And the natural gas sales guy isn’t going to charge any more, because if they charge more, they won’t sell all the natural gas. But if they charge less, they’re leaving money on the table.”

This loop is what creates the extreme natural gas price readings that economists and regulators have tracked over decades. The Algonquin Citygate hub, where New England receives much of its natural gas supply, regularly sees winter prices that dwarf those in the rest of the country. During recent cold snaps, Algonquin prices have climbed above $35 per million British thermal units, compared to national averages around $3.37. Data from ISO-New England confirm that oil and dual-fuel-fired generation overtakes natural gas-fired supply during the tightest conditions.

A Structural Problem, Not a Weather Problem

It would be tempting to blame these spikes purely on the weather. But the underlying cause is structural, and recognizing that distinction matters for anyone making decisions about energy infrastructure, policy, or cost management.

The core issue is constrained pipeline capacity. New England has long resisted major pipeline expansion, leaving the region dependent on a network that simply cannot move enough gas when winter demand peaks. As Philip Bartlett, chairman of the Maine Public Utilities Commission, has said publicly, being overly reliant on natural gas within a pipeline-constrained system is not workable.

The region does have options when pipelines max out. It can import liquefied natural gas, which at peak demand supplies up to 35 percent of New England’s gas supply. It can draw from Canadian hydro imports via interconnections to the north. And it can rely on fuel oil storage at dual-fuel plants. But each of these alternatives imposes its own constraints, and none eliminates the supply chain’s fragility.

For organizations that manage large energy costs or operate in affected regions, Somani’s framing offers a sound mental model. The question is not simply whether the weather will be cold this winter. The question is how much pipeline capacity exists, how much residential heating demand will compete with generation, and at what price point the oil generators become economically necessary.

What Needs to Change

Potential longer-term approaches to East Coast power price volatility may involve a combination of infrastructure investments, demand flexibility, and generation diversification. Expanding pipeline capacity, adding battery storage, building more renewable energy generation to reduce dependence on gas during peak periods, and modernizing transmission infrastructure all help reduce the region’s exposure to these spikes.

Some of these investments are already underway. Proposals for renewable energy projects in northern Maine, along with accompanying transmission lines, are moving forward. Battery storage is growing as operators recognize its value in absorbing cheap off-peak power and dispatching it during high-demand hours.

But the structural change is gradual, and in the meantime, the same market mechanics will continue to drive winter price spikes whenever temperatures fall hard enough and long enough to strain the pipeline network. The fundamentals have not changed, and neither has the logic: when the cheapest fuel runs short, the most expensive unit sets the price, and everyone downstream pays accordingly.