Natural Gas Basis, Explained

Natural gas basis is the difference between the NYMEX Henry Hub futures price and the price of gas at the location where it is actually delivered to you. Henry Hub is a pipeline interconnect in Erath, Louisiana. Your facility is not there. Moving gas from the hub to your utility's city gate costs money, and when pipelines into your region are full, that cost rises sharply. Basis is that difference, quoted in dollars per MMBtu, and in constrained regions it can be a larger share of your winter price than the commodity itself.

Most commercial buyers see one number on a supplier quote and assume it tracks the national market. It does not. A fixed price for gas delivered in Boston or New York is two prices added together, and only one of them moves with the headlines. This piece explains the other one, because it is where most of the pricing risk sits for a facility in the Northeast, the Mid-Atlantic, or the upper Midwest.

The two halves of a delivered gas price

Every fixed-price commercial gas contract in a deregulated market is built from the same components:

• NYMEX, or the commodity. The Henry Hub futures price for each delivery month. It is public, traded every day, and the same for every buyer in the country.
• Basis. The location adjustment from Henry Hub to the pipeline receipt point or city gate that serves your utility. It is traded too, in forward basis swaps, but it is far less visible and it differs by region.
• Transport and fuel. The pipeline's tariff to move the gas, plus the small percentage of gas the pipeline retains as fuel to run its compressors.
• Supplier margin and broker fee. The supplier's cost of hedging, credit and service, and the fixed per-unit fee paid to a broker where one is involved.

Add them up and you have the price per MMBtu, or per Dth (dekatherm; the two are equal for practical purposes), or per therm (one tenth of a Dth), depending on how your utility bills. A quote at $4.10 per Dth in Pennsylvania and $5.60 per Dth in Massachusetts for the same month usually have identical NYMEX in them. The gap is basis and transport.

What sets basis

Basis is a pipeline capacity question. Gas producing regions, the Appalachian Marcellus and Utica fields above all, have more gas than the pipelines out of them can carry. Consuming regions at the end of long pipelines, New England above all, have more demand on a cold morning than the pipelines into them can deliver. Price falls where gas is trapped and rises where gas is scarce.

That produces a pattern that holds year after year:

• Negative basis near production. Pricing points in western Pennsylvania and eastern Ohio routinely trade below Henry Hub, because the gas has to be discounted to find a pipeline out. A facility there buys gas cheaper than the national price.
• Positive and volatile basis at the end of the line. The Algonquin city gate serving Boston, and the Transco Zone 6 points serving New York and New Jersey, trade above Henry Hub, and on the coldest days the premium can be several multiples of the commodity price. The pipeline is full, power plants and heating load are competing for the same molecules, and the price clears wherever it has to.
• Mild, stable basis in the middle. Chicago, Michigan and much of the Mid-Atlantic sit close to Henry Hub most of the year, with winter premiums that are real but moderate.

Two things change basis over time. New pipeline capacity into a region compresses it; a pipeline project that is delayed or cancelled keeps it wide. And new demand changes it: LNG export terminals on the Gulf Coast pull gas south and east, and gas-fired generation in constrained regions bids against heating load on the days that matter most.

Why basis matters more in winter

The NYMEX curve has a winter premium, but it is modest; the market is national and winter weather in one region is offset by mild weather in another. Basis has no such offset. On a January morning in New England the pipelines into the region are at capacity and there is no second route. Spot basis at Algonquin has, in past winters, moved by more in a single week than the entire NYMEX curve moved over a year.

That asymmetry is the whole point of understanding basis. A buyer who hedges NYMEX and leaves basis floating has protected the stable half of the price and left the volatile half open. In Texas, Ohio or Illinois that may be a reasonable choice, because basis is usually small and sometimes negative. In Massachusetts, Connecticut, New York or New Jersey it is the opposite of what a risk-averse buyer wants.

The three ways a contract prices basis

When we take a commercial gas load to market, the structure question is really a basis question. Suppliers will quote any of these, and the right one depends on where the meters are:

1. All-in fixed. NYMEX, basis and transport are all locked into one price per Dth for the term. The buyer has no exposure to either leg. This is the right default for a facility in a constrained region with winter heating load, and for any buyer whose budget cannot absorb a bad month.
2. NYMEX plus floating basis. The commodity is fixed at signing; basis is passed through at the monthly published index for the delivery point. Cheaper on average in regions where basis is low or negative, because the supplier does not have to charge a premium for carrying winter basis risk. Appropriate in Pennsylvania, Ohio and much of the Midwest; a gamble in New England.
3. Index plus fixed basis, or basis locked separately. The commodity floats with NYMEX month by month and basis is fixed. Buyers use this when they expect the national price to fall and want the upside, but cannot tolerate a location blowout. It is also how a layered strategy works: lock basis for the winter strip early, then lock NYMEX in tranches as the curve dips.

The important discipline is to price each leg on the same day across every supplier. A quote that is cheaper because the supplier is carrying less basis risk is not cheaper; it is a different product. When Inertia runs a bid, the {F('supplier_count')} suppliers quote identical structures on identical terms, so the comparison is real. Our guide to commercial natural gas procurement covers the rest of that process.

A worked example

Take a food processing plant in New Jersey burning 40,000 Dth a year, two thirds of it between November and March. Suppose the NYMEX strip for the contract term averages $3.50 per Dth. Winter basis at the relevant Transco Zone 6 point might be quoted forward at $3.00 per Dth for January and February and $0.60 for the shoulder months; summer basis near $0.40. Weighted by the plant's load shape, basis alone is roughly $1.70 per Dth on average, or about $68,000 a year, nearly half the commodity cost. (These are illustrative figures to show the arithmetic, not a forecast.)

Now the choice. All-in fixed locks that $68,000. NYMEX-plus-floating saves the supplier's risk premium, perhaps $0.15 to $0.30 per Dth, but if one winter month settles at twice the forward basis, the plant pays an extra $40,000 in that month alone. For a plant whose gas budget is set by a finance team in October, the first structure is the right one. For a 24/7 flat load in Ohio with negative basis, the second usually is.

What to ask before you sign

• Which pricing point is the basis quoted against? It should be the point your utility actually takes delivery at, not a cheaper neighboring point.
• Is basis fixed for the full term, or only for the first year with a reopener?
• If basis floats, which published index settles it, and is there a cap?
• How is pipeline fuel retention charged: inside the fixed price, or as a percentage pass-through?
• What happens to the price if the utility changes its transport tariff mid-term? That is a pass-through clause, and our note on energy contract clauses explains which ones to resist.

Basis is not a reason to avoid fixing a gas price. It is the reason to make sure the fixed price includes it, in the regions where it bites, and to make sure you are not paying a winter premium for it in the regions where it does not.