Prices and volatility: Henry Hub, basis and your power bill

Gas is priced in dollars per million Btu, written $/MMBtu. One MMBtu is about 1,000 cubic feet of pipeline gas, enough to run a typical home furnace for a few cold days. EIA's October 2026 outlook put the 2025 average Henry Hub spot price at $3.53 and forecast $3.48 for 2026 and $3.16 for 2027. Those averages hide the swings, and the swings are what hit power bills.

January 2026 averaged $7.72 at Henry Hub, more than double the annual forecast, as winter storm Fern drove heating demand. In February 2021, during Winter Storm Uri, Henry Hub hit $23.61 on February 17, and one Oklahoma hub averaged nearly $1,193. Gas is cheap most of the time and brutally expensive some of the time. Any argument about a gas plant's costs needs both halves.

Henry Hub, the benchmark

Henry Hub is a real place, a pipeline interconnection in Erath, Louisiana, where more than a dozen pipelines meet. NYMEX natural gas futures settle against delivery there, so traders, utilities and EIA treat its price as the national reference. When a news report says "natural gas prices rose 10% today," it almost always means Henry Hub futures.

Most gas does not trade at Henry Hub. It trades at dozens of regional hubs and citygates, each with its own price. That is where basis comes in.

Regional basis

Basis is the regional price minus Henry Hub. If gas in Chicago sells for $4.20 when Henry Hub is $4.00, Chicago basis is plus 20 cents. Basis reflects how hard it is to get gas from supply to demand. A region with plenty of pipeline capacity and nearby production often trades below Henry Hub. A region at the end of a crowded pipeline on a cold morning can trade far above it.

EIA's weekly report for February 18, 2021, shows how far basis can stretch:

Hub	Wed Feb 10, 2021	Peak during storm	Peak date
Henry Hub (Louisiana)	$3.68	$23.61	Feb 17
Chicago Citygate	$3.99	$129.52	Feb 12
SoCal Citygate	$4.97	$144.00	Feb 12
Houston Ship Channel	about $4.50	$400.00	Feb 16
OGT (Oneok, Oklahoma)	$8.60	about $1,192.86	Feb 17

Daily spot prices like these apply only to gas bought on the spot that day. Utilities that had locked in supply under contract or held gas in storage paid far less. Those that had to buy on the spot market, or whose contracts were indexed to daily prices, were hit with costs that ran into the billions in Oklahoma, Kansas and Texas, much of it later recovered from customers over years through securitized bonds and surcharges approved by state regulators.

In the West, basis tends to blow out when pipelines from the Rockies and Canada run full during cold weather or when a pipeline outage removes supply. The EIA weekly series that used to make this easy to follow ended with its January 22, 2026 edition, so regional prices now come mostly from EIA's monthly data, commercial services such as Natural Gas Intelligence and S&P Global, and utility filings.

What makes prices spike

EIA's list of price drivers is a good checklist.

• Weather. Cold winters push heating demand. Hot summers push power plant demand. Summer burn can also leave storage lower going into winter.
• Production disruptions. Wellhead freeze-offs in cold snaps cut supply exactly when demand peaks. EIA reported Texas daily dry gas output fell by almost half on February 17, 2021, mostly from freeze-offs.
• Storage levels. Storage below the five-year average going into winter makes markets nervous.
• Pipeline constraints. Gas cannot move instantly from where it is to where it is needed. Constraints show up as basis.
• Exports. LNG export growth adds steady demand that competes with domestic users.
• Competing fuels. When coal is cheaper, some plants switch, easing gas demand. EIA notes US industry's ability to switch fuels has declined.

How gas costs reach a power bill

EIA says generation is the largest component of electricity prices. Fuel is a big part of generation costs for any utility that burns gas. The average US residential price in 2025 was 17.30 cents per kWh, per EIA.

In most states, a regulated utility recovers fuel costs through a fuel adjustment clause (sometimes called a power cost adjustment or energy cost recovery rider). The utility forecasts its fuel and purchased power costs, charges a rate based on that forecast, then trues up the difference later, often annually, after the state commission reviews it. If gas spikes in January, customers may not see most of the cost until a rider increase months later. If gas falls, they get a credit later.

Designs vary a lot. Some states share the risk, letting the utility recover only a percentage of the variance (say 90%) so it has a reason to buy carefully. Some utilities hedge, buying part of their gas in advance at fixed prices. In organized wholesale markets such as PJM, ERCOT or MISO, gas plants often set the market clearing price in many hours, so gas prices pass through wholesale power prices even to utilities that own no gas plants at all.

The spark spread

Gas plant owners in wholesale markets watch the spark spread: power price minus fuel cost at a given heat rate. If power sells for $45 per MWh and a 7,000 Btu/kWh plant pays $3.50 for gas, fuel costs $24.50 and the spread is $20.50 to cover other operating costs and profit. Anyone can use the same arithmetic to check a claim that a plant "loses money" or "is the cheapest option." Ask what gas price and what power price the claim assumed.