Why is natural gas the most seasonal market there is?

Every commodity in this course has a calendar. Natural gas has a tyrant. It combines the two hardest physical constraints available — it is expensive to store and very expensive to move — and the result is the most violent, most regional and most weather-driven market in the mainstream commodity complex.

The physical problem

Gas is a gas. At ambient conditions it occupies enormous volume for very little energy, so it travels economically in only two ways:

• By pipeline, which is fixed infrastructure with a fixed route and a fixed capacity; or
• As LNG, which means chilling it to about −162 °C so it becomes a liquid occupying roughly 1/600th of its gaseous volume. That requires a multi-billion-dollar liquefaction plant at one end, a purpose-built refrigerated ship in the middle, and a regasification terminal at the other.

Neither can be improvised. You cannot put gas on a truck to Europe because a European price is attractive this week.

Consequence one: there is no world gas price

Because arbitrage is slow and capital-intensive, gas trades at genuinely different levels on different continents:

• Henry Hub (Erath, Louisiana) — the US benchmark, quoted in $/MMBtu, futures contract 10,000 MMBtu.
• TTF (Netherlands) and NBP (UK) — the European benchmarks, quoted in €/MWh and p/therm.
• JKM — the Japan-Korea Marker, the reference for spot LNG delivered into North Asia.

How far apart can they get? In the summer of 2022, European TTF traded around €340/MWh at its peak. Converting at roughly 3.41 MMBtu per MWh, that is close to €100 per MMBtu — and with the euro near parity with the dollar, roughly $100/MMBtu. Henry Hub over the same period was under $10. The same molecule, at about ten times the price, because there were not enough ships, terminals or hours to move it.

For oil, that gap would be arbitraged away in weeks. For gas, closing it takes years of construction.

Consequence two: the storage calendar

US gas storage runs on a schedule so consistent it is treated as a season in its own right:

• Injection season: roughly 1 April to 31 October. Production exceeds demand; the surplus goes underground into depleted reservoirs and salt caverns.
• Withdrawal season: roughly 1 November to 31 March. Heating demand exceeds production; the buffer is drawn down.

Working gas in storage typically peaks near 3,700–3,900 Bcf at the end of the injection season in late October or early November, and troughs around 1,500–1,900 Bcf at the end of March. The whole market spends the year watching that one number relative to its five-year average — which is why the EIA weekly natural gas storage report, published Thursdays at 10:30 ET, is a scheduled volatility event.

Why a cold week is a price event

Now the arithmetic that explains gas's reputation. Suppose an extended cold snap adds 15 Bcf per day of heating demand for ten days:

15 × 10 = 150 Bcf pulled out of storage beyond plan.

Against a full storage base near 3,800 Bcf that is about 4% of the entire national buffer, gone in under two weeks. And there is no way to produce it: wells cannot be turned up on demand, and in a deep freeze wellheads and gathering lines actually freeze off, so supply often falls precisely when demand spikes.

Supply is fixed, storage is finite, demand is weather. The only variable free to move is price — which is why natural gas can move 10–20% in a session on a revision to a weather model. Not on weather. On the forecast of weather, days ahead of it.

The double hump

Winter heating is the classic driver, but gas-fired power generation has added a summer peak in many markets: air-conditioning load raises electricity demand, which raises gas burn. So annual demand in a place like the US now often shows two humps — a large winter one and a smaller summer one — with the shoulder months in between doing the storage refilling.

And the curve shows it plainly

Because a molecule in January is genuinely worth more than a molecule in April, gas futures curves are openly, unapologetically seasonal: winter contracts habitually trade above the following spring's. The winter-summer spread is a market in its own right, traded by storage operators whose entire business is buying cheap gas in summer and selling it dear in winter, minus the cost of keeping it.

Note what that is: the storage operator is not forecasting. They are monetising the spread, which the curve shows them today.

Try it now

1. Five years of continuous natural gas is below. Drop a Level across the top of each winter and mark the November-to-March windows: where the large moves cluster is the lesson, and it clusters in the same months every year.

2. Measure the largest single-day percentage move you can find in that history and check what part of the calendar it fell in. Then do it for the second largest. Two out of two in the same season is a coincidence; five out of five is a mechanism.
3. Redo the cold-snap arithmetic with 20 Bcf/day for 14 days. (280 Bcf — over 7% of a full storage base.) Then say, in one neutral sentence, why that is a price problem rather than a production problem. This is a description of a mechanism, not a forecast about any winter.