Natural Gas Pricing Hubs and Seasonality

Why Natural Gas Pricing Differs by Location

Natural gas prices vary by where you measure them. Unlike oil (which ships globally in tankers), natural gas moves through pipelines that create regional price differences of $0.50-$3.00 per million BTUs (MMBtu) depending on distance from production and local demand conditions.

The practical point: understanding hub pricing and seasonal patterns helps you interpret natural gas data without assuming that “the price” is a single national number.

Henry Hub: The US Benchmark

Henry Hub in Erath, Louisiana serves as the primary US natural gas benchmark. NYMEX futures contracts settle against Henry Hub prices, making it the reference point for the entire domestic market.

Why Henry Hub became the benchmark:

• Located at the intersection of 13 interstate and intrastate pipelines
• Connected to major consuming regions (Gulf Coast, Southeast, Midwest)
• Liquid trading market with daily physical volumes exceeding 2 billion cubic feet
• Storage facilities nearby provide deliverability

The calculation: When you see “natural gas at $2.50,” that’s the Henry Hub spot price in dollars per MMBtu.

Current price context (2023-2024): Henry Hub prices ranged from $1.50 to $3.50/MMBtu, down significantly from 2022 peaks near $9/MMBtu. The decline reflects increased domestic production and reduced export disruptions.

Regional Pricing Hubs (Basis Spreads)

Other US hubs trade at premiums or discounts to Henry Hub. This difference is called the basis spread.

Basis Spread = Regional Hub Price - Henry Hub Price

Example: If Henry Hub trades at $2.50 and Waha trades at $1.00, the Waha basis is -$1.50. The discount exists because Permian Basin gas has limited pipeline takeaway capacity, creating localized oversupply.

The core principle: negative basis means local oversupply; positive basis means local supply constraints. Pipeline capacity determines which regions can export surplus gas and which must discount it.

Seasonal Demand Patterns

Natural gas demand follows predictable seasonal cycles driven by weather and power generation.

Winter Heating Season (November - March)

• Residential and commercial heating demand peaks
• Coldest months (December-February) see highest prices
• Price spikes during polar vortex events can be extreme ($5-$200/MMBtu intraday)

Summer Cooling Season (June - August)

• Air conditioning drives electricity demand
• Gas-fired power plants run at high capacity
• Creates secondary demand peak (smaller than winter)

Shoulder Seasons (April-May, September-October)

• Lowest demand periods
• Prices typically bottom during shoulder months
• Storage injection occurs (building inventory for winter)

Typical seasonal price range:

• Winter peak: $3.50-$6.00/MMBtu (can spike much higher in extreme cold)
• Summer secondary peak: $2.50-$3.50/MMBtu
• Shoulder season lows: $1.50-$2.50/MMBtu

The spread between winter and summer averages $1.00-$3.00/MMBtu in normal years.

Storage Cycle (The Physical Buffer)

Underground storage facilities balance seasonal supply and demand mismatches.

Injection Season (April - October)

• Producers inject gas into storage when demand is low
• Target: build inventory before winter heating season
• Storage levels reported weekly by EIA (every Thursday at 10:30 AM ET)

Withdrawal Season (November - March)

• Utilities withdraw gas to meet heating demand
• Storage draws down through winter
• Low storage entering winter = bullish price signal

Storage capacity context:

• US working gas capacity: approximately 4.7 trillion cubic feet (Tcf)
• Typical end-of-injection (October): 3.5-3.9 Tcf
• Typical end-of-withdrawal (March): 1.5-2.0 Tcf

The calculation: Storage as percentage of 5-year average indicates tightness.

• Above 100%: Bearish (ample supply)
• 95-105%: Neutral
• Below 95%: Bullish (supply concerns)

Example: October 2023 storage at 3.8 Tcf was 105% of the 5-year average, signaling adequate supply and contributing to lower prices through winter 2023-24.

How Weather Events Create Price Spikes

Extreme weather causes rapid price movements because natural gas cannot be easily stored or transported on short notice.

Winter 2021 Texas Freeze:

• February 2021 polar vortex hit Texas
• Henry Hub spiked from $3/MMBtu to $23/MMBtu within days
• Some regional hubs saw prices exceed $100/MMBtu briefly
• Cause: frozen wellheads cut production; frozen pipes blocked delivery

Winter 2022-23:

• Mild winter reduced heating demand below forecasts
• Henry Hub fell from $7/MMBtu (November) to $2.50/MMBtu (February)
• Storage withdrawals were smaller than expected

The practical point: weather forecasts move natural gas prices more than almost any other commodity. A 10-day forecast change from “mild” to “cold” can move prices 10-20% within hours.

Basis Volatility: When Regional Prices Diverge

During supply stress, regional prices can diverge dramatically from Henry Hub.

Scenario: Pipeline Outage

• If a major pipeline to the Northeast goes offline in January, regional prices spike
• New York/New England basis might jump from +$0.50 to +$10.00 overnight
• Henry Hub might only move +$0.30 because the constraint is regional

Scenario: Production Basin Oversupply

• Permian Basin gas production exceeds pipeline capacity
• Waha basis goes deeply negative (-$2.00 or worse)
• Some producers pay to have gas taken (negative prices)

What the data confirms: basis risk is real. A hedge at Henry Hub doesn’t protect against regional price spikes if you’re consuming gas in a different location.

Key Reports and Data Sources

How to use storage reports:

1. Check actual vs. consensus estimate (Bloomberg survey)
2. Compare to 5-year average for same week
3. Large misses (20+ Bcf vs. estimate) move prices immediately

Monitoring Checklist

Essential (understand the market)

• Track Henry Hub spot and near-month futures prices
• Watch weekly EIA storage reports vs. estimates
• Note seasonal position (injection or withdrawal season)
• Check 10-14 day weather forecasts for major consuming regions

High-impact (for active tracking)

• Compare regional hub prices to identify basis trends
• Monitor pipeline maintenance schedules (planned outages)
• Track LNG export volumes (growing demand driver)
• Review monthly production data by basin

Optional (for deeper analysis)

• Model storage trajectories vs. 5-year range
• Track heating degree days (HDDs) and cooling degree days (CDDs)
• Monitor basis spreads at key delivery points
• Follow rig count trends for forward production signals

Practical Applications

For portfolio context:

• Natural gas prices affect utility company earnings
• Energy sector weights in indexes include gas producers
• Regional price differences matter for companies with geographically concentrated operations

For economic context:

• High gas prices increase electricity costs and inflation readings
• Low gas prices benefit industrial users and consumers
• Storage levels indicate supply adequacy for winter reliability

Example interpretation: If Henry Hub is at $2.50, storage is 110% of the 5-year average, and the 10-day forecast shows mild temperatures, expect prices to remain stable or drift lower. If a cold front appears in forecasts, prices will react before the cold arrives.

References

Source: US Energy Information Administration (EIA). Natural Gas Weekly Update and Weekly Natural Gas Storage Report. 2024.

Source: CME Group. Henry Hub Natural Gas Futures Contract Specifications. 2024.

Source: S&P Global Commodity Insights. North American Natural Gas Basis Analysis. 2024.