Natural Gas Futures in Depth: Henry Hub, the Storage Report, Winter Risk and LNG

NYMEX Henry Hub natural gas futures (code NG) are contracts for 10,000 million British thermal units (MMBtu) of gas delivered at a steady rate across a calendar month into pipelines at the Henry Hub in Louisiana, and they are the benchmark price for North American gas. They are among the most volatile major futures markets because gas is hard to store at the margin, demand swings with the weather, and the United States now exports a large share of its supply as liquefied natural gas (LNG), tying a regional market to world prices.

In short: one NG contract moves $10 for every $0.001 per MMBtu, so a 10-cent move is $1,000. Trading in a month’s contract ends three business days before that month begins, and anyone still holding it then must make or take delivery through the pipeline system over the whole month. The market’s weekly heartbeat is the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report, released Thursdays at 10:30 a.m. Eastern Time, which estimates the gas held in underground storage from a sample survey of storage operators. Winter is the risk season: cold snaps can multiply spot prices in days, as in February 2021 and January 2026. The 2022 price spike showed the other new driver: LNG export demand linked to Europe’s energy crisis, and what happens when an export terminal suddenly stops.

This piece builds on crude oil futures explained, which covers the oil side of the energy complex, and on the curve concepts in contango and backwardation.

A common misconception: “natural gas trades like oil”

Both are energy and both trade on NYMEX, but the physics differ. Oil moves by tanker, pipeline and truck to almost anywhere and can be stored in tanks, so its price is set in a global market with a broad storage buffer. Natural gas in North America moves almost entirely by pipeline, and storage is mostly underground: depleted reservoirs, aquifers and salt caverns, which EIA classifies separately. Consumption roughly follows heating demand in winter and power generation in summer, while production is steady. The result is a market organised around one annual cycle, filling storage from spring to autumn and drawing it down in winter, with a price that can jump violently when a cold spell meets limited deliverability.

The contract

NYMEX Henry Hub Natural Gas Futures are governed by Chapter 220 of the NYMEX Rulebook. The core terms, cross-checked against the Federal Energy Regulatory Commission’s description of the contract in its 2007 Amaranth order and NYMEX’s own rule filings with the CFTC:

Term	Specification
Contract unit	10,000 MMBtu
Price quotation	U.S. dollars and cents per MMBtu
Minimum tick	$0.001 per MMBtu = $10 per contract
Termination of trading	Three business days before the first calendar day of the delivery month
Delivery	Over the course of the delivery month, at the buyer’s interconnection with Sabine Pipe Line Co.’s Henry Hub in Louisiana
Delivery terms (Rule 220104)	Free-on-board at the buyer’s interconnection point; delivery occurs when gas passes through that point “via physical flow or displacement”, at which time the buyer bears the risk of loss; the Hub’s intra-hub transfer service is an acceptable buyer interconnection point
Quality	Gas meeting the specifications of Sabine Pipe Line’s FERC-approved tariff

The 2016 amendment to Rule 220104 (NYMEX Submission 16-080) is a good illustration of how physical the contract is: NYMEX added “displacement” to the rule to confirm that gas can be delivered by counter-flow scheduling on the pipeline, which Sabine’s tariff gives scheduling priority, rather than only by molecules physically flowing toward the buyer.

Expiry dates in practice. The rule counts back three business days from the first calendar day of the delivery month. For the December 2026 contract, December 1 is a Tuesday; counting back over Monday November 30, Friday November 27 and skipping Thanksgiving on November 26 gives a last trading day of Wednesday, November 25, 2026. For January 2027, counting back from New Year’s Day gives Tuesday, December 29, 2026. Check CME’s published calendar before relying on any computed date.

Why the final settlement price matters so much

FERC’s 2007 order in the Amaranth case explains that the NG final settlement price sets the value of a large volume of other transactions: NYMEX’s Henry Hub swap futures and ICE’s natural gas swaps float against it, and physical gas for the following month is often priced off it. FERC preliminarily concluded that Amaranth had sold extraordinary volumes in the last 30 minutes of trading before expiry on February 24, March 29 and April 26, 2006 to depress the settlement price and benefit larger positions elsewhere. FERC also noted that the vast majority of NG futures contracts never go to delivery. The settlement mechanics are a reason exchanges watch expiry days closely.

Worked example: P&L per tick

All prices are illustrative.

A trader buys 2 January 2027 NG contracts at $3.850 per MMBtu.
The contract rises to $4.212.
Move: $4.212 - $3.850 = $0.362, or 362 ticks.
P&L: 362 ticks x $10 x 2 contracts = $7,240.

Some useful conversions: one cent ($0.01) is $100 per contract; ten cents is $1,000; one dollar is $10,000. On a $3.00 contract, notional value is $30,000.

Delivery quantity. A trader who held one January contract into delivery would be committed to roughly 10,000 / 31 = 322.6 MMBtu a day for the 31 days of January, and about 357.1 MMBtu a day for a 28-day February. Delivery involves nominations and scheduling on the pipeline, which is why retail brokers generally require positions to be closed well before termination. How delivery works across commodities is covered in physical delivery in depth.

The weekly storage report

EIA publishes the Weekly Natural Gas Storage Report (WNGSR) at 10:30 a.m. Eastern Time each Thursday, except in some holiday weeks. EIA took over from the American Gas Association, whose last weekly report was published on May 1, 2002; EIA’s first release came on May 9, 2002. EIA’s published methodology explains how the number is built:

The survey. Form EIA-912 asks a sample of underground storage operators for working gas in storage as of 9:00 a.m. Central Time on Friday. Reports are due by 5:00 p.m. Eastern Time the following Monday.
The sample. EIA draws it from the monthly census of all storage operators (Form EIA-191, about 133 operators and 410 fields). It uses a stratified design with probability proportional to size across six strata: East, Midwest, Mountain, Pacific, South Central salt and South Central nonsalt. Large operators are always included. The target is a relative standard error of no more than 5% in each stratum, and the result is about 80 to 85 respondents typically covering at least 90% of the volumes in each stratum. Since 2018, all eight Pacific operators are surveyed.
The estimate. For operators not in the weekly sample, EIA estimates volumes from each company’s 12-month moving average of monthly data, adjusted by the week-to-week behaviour of sampled companies in the same stratum and by each company’s own seasonal pattern.
Reclassifications. Operators occasionally reclassify gas between base gas and working gas. When reported reclassifications total 4 billion cubic feet (Bcf) or more, EIA reports an implied flow separately from the net change, so the market can tell real injections and withdrawals from accounting moves.
Sampling error. Each report publishes coefficients of variation and standard errors for the net change.

Reading a real report

The report released November 5, 2026, for the week ending October 30, 2026:

Measure	Value
Working gas in storage, Lower 48	3,801 Bcf
Net change for the week	+77 Bcf
Versus a year earlier	109 Bcf lower (-2.8%)
Versus the 2021-2025 five-year average	54 Bcf higher (+1.4%)
Standard error of the total net change	1.1 Bcf
South Central salt, versus five-year average	-8.1%

Traders compare the reported net change with what they expected, from surveys and weather-driven models. A 3 Bcf “miss” against expectations is several times the 1.1 Bcf sampling standard error, so the market treats it as information. What it does to prices is not mechanical. Even on illustrative terms, a 5-cent reaction is $500 per contract, and reactions in winter, when stocks are falling and the cushion is uncertain, tend to be larger.

The salt cavern line matters more than its size suggests. Salt caverns can inject and withdraw quickly, so they balance short-term swings; a low salt inventory going into winter means less fast-response gas when a cold snap arrives.

Winter volatility

The numbers

EIA’s analysis of Henry Hub front-month futures (Today in Energy, June 4, 2024) measured 30-day historical volatility of 171% in February 2022, the highest since at least 1994, an average of 91% across 2022, and 69% in 2023. Annualised volatility converts to a daily standard deviation by dividing by the square root of 252:

Annualised volatility	One-standard-deviation daily move	On a $3.00 contract	On an $8.00 contract
69% (2023 average)	4.35%	$1,304	$3,477
91% (2022 average)	5.73%	$1,720	$4,586
171% (February 2022)	10.77%	$3,232	$8,618

At 171% volatility, a routine one-standard-deviation day moves one contract by more than 10%, which is why gas margins are high relative to notional value and change often (see SPAN and futures margin models). CME’s 2024 SPAN 2 filing also notes that physically delivered contracts show a strong Samuelson effect, with volatility rising as expiry nears and the front month decoupling from the second, and natural gas has its own pod in SPAN 2, the margin framework CME began rolling out for energy in 2023.

Winter Storm Fern, January 2026

EIA’s daily Henry Hub spot series shows the price at $3.06 per MMBtu on January 16, 2026 and $30.72 on January 23, the highest in the series, above the $23.86 recorded on February 17, 2021 during Winter Storm Uri. Other price reporters date and measure the peak differently, so treat the exact figure as series-specific. EIA’s monthly average for January 2026 was $7.72, against $4.26 in December 2025.

EIA’s Today in Energy of February 5, 2026 explained the mechanics:

Working gas fell 360 Bcf in the week ending January 30, 2026, the largest weekly net withdrawal in the report’s history and 89% (170 Bcf) more than the five-year average for that week.
Extreme cold from New Mexico to New England raised heating and power demand; residential and commercial consumption on January 23 to 26 averaged 29% (13.9 Bcf per day) above the five-year average for those days, citing Bloomberg data.
At the same time, freeze-offs and shut-ins cut production, with Gulf Coast temperatures averaging below freezing on January 25.

Demand up, supply down, all at once: that combination is what winter risk means in gas, and it hits spot and the prompt futures month hardest.

LNG exports: the new structural driver

EIA’s annual export data shows how quickly LNG changed the U.S. balance:

Year	U.S. LNG exports (Tcf)	Average (Bcf/d)
2016	0.19	0.51
2019	1.82	4.99
2022	3.87	10.59
2024	4.37	11.93
2025	5.51	15.09

(Bcf/d calculated from EIA’s annual totals.) EIA reported on September 1, 2026 that exports averaged 17.4 Bcf/d in the first half of 2026, 23% more than a year earlier, the fastest growth since large-scale exports began in 2016. Plaquemines LNG was exporting at full capacity, Corpus Christi Stage 3 was exporting from six of its seven trains, and Golden Pass LNG, the ninth U.S. export terminal, began exporting in April 2026, according to EIA. EIA also reported that disruptions to shipments through the Strait of Hormuz in March 2026 cut off about 20% of global LNG supply, mostly from Qatar, pushing international LNG prices higher and keeping U.S. terminals running near maximum output.

Two things follow for futures. First, export demand is large, steady, and largely insensitive to Henry Hub prices while international prices stay well above U.S. prices, so it tightens the balance in every season. Second, a terminal outage removes billions of cubic feet a day of demand overnight, which is bearish for Henry Hub even as it is bullish for overseas prices.

The 2022 price spike

EIA’s monthly Henry Hub spot averages trace the episode:

Month	Henry Hub spot, monthly average ($/MMBtu)
January 2022	4.38
April 2022	6.60
May 2022	8.14
June 2022	7.70
August 2022	8.81
October 2022	5.66
January 2023	3.27

The daily spot peak in EIA’s series was $9.85 on August 22, 2022, the same day the front-month futures settled at $9.68 in EIA’s futures series. EIA attributes the year’s extreme volatility partly to increased European demand for LNG after Russia’s full-scale invasion of Ukraine in February 2022, and partly to the explosion at the Freeport LNG export terminal in June.

Worked example: the Freeport outage

EIA’s Today in Energy of July 19, 2022 reported that a fire at Freeport LNG’s liquefaction plant led to the full shutdown of the facility on June 8, 2022, cutting U.S. export capacity by about 2.0 Bcf/d. The Henry Hub spot price fell $1.27 to $8.16 on June 9 and ended June at $6.54. EIA estimated LNG exports fell to 10.1 Bcf/d in June, down 1.5 Bcf/d from May. Gas that had been bound for export stayed in the U.S. market.

In EIA’s daily series of NYMEX front-month futures, the contract settled at $8.609 on June 13 and $7.189 on June 14 as the market priced a longer outage:

Change: $7.189 - $8.609 = -$1.420 per MMBtu, or -16.5%.
Per contract: -1,420 ticks x $10 = -$14,200 in one day.
At 10 contracts long: -$142,000 of variation margin due the next morning.

A hedger who was short futures against gas production gained the same amount on the futures, offsetting lower physical sales prices. A speculator who was long because of the European story was right about Europe and lost money anyway, because Henry Hub is a U.S. price and the outage trapped supply at home.

By January 2023 the monthly average had fallen to $3.27. EIA linked the decline to warmer than normal weather, higher production and higher storage, with January withdrawals 55% (371 Bcf) below the five-year average.

How hedgers use the curve

Described as practice, not advice:

Producers sell futures for future months to lock in revenue, often across a 12-month strip.
Utilities and local distribution companies buy winter months ahead of time to stabilise customer costs.
Storage operators buy summer gas and sell winter futures when the spread pays for injection, withdrawal and financing; the winter premium in the curve is the market’s price for storage.
LNG exporters and buyers pair Henry Hub-linked purchase contracts with futures to manage the domestic leg of their margin.

These are calendar and location spreads as much as outright positions, which is why spread risk dominates professional gas books (see famous futures blowups for what happens when spread positions get too large).

What can go wrong

Weather gaps. A forecast change over a weekend can move the prompt month by double digits in percentage terms before most traders can react.
Expiry and delivery. Holding past termination means delivering or taking gas over the whole month at Henry Hub. Brokers will close positions for clients well before that.
Spread blowups. Winter/summer spreads can move more than outright prices, and spread margin assumes they will not.
Margin calls at the worst time. Clearing margins rise with volatility; a 10% daily move on a high-priced contract is several thousand dollars a contract.
Event risk outside the U.S. LNG ties Henry Hub to world events, but not in a simple direction: an overseas shortage can be bullish, while an outage at a U.S. export terminal is bearish.
Data revisions and surprises. The storage report is a sample estimate with published standard errors, and EIA revises reclassifications separately.

The short version

NYMEX Henry Hub natural gas futures are 10,000 MMBtu contracts, $10 a tick, that stop trading three business days before the delivery month and then deliver gas ratably over the month into pipelines at Henry Hub. The market’s weekly signal is EIA’s storage report, a stratified sample estimate of working gas published Thursdays at 10:30 a.m. Eastern, with a standard error of about 1 Bcf on the net change. Winter is when the market breaks: in January 2026 EIA’s spot series reached $30.72 and the storage report showed a record 360 Bcf withdrawal. LNG exports, which grew from 0.5 Bcf/d in 2016 to more than 17 Bcf/d in the first half of 2026, now link Henry Hub to the world, and the 2022 spike and the Freeport outage showed that link can push prices in either direction. Everything here describes mechanisms, not trading suggestions.