Natural Gas Pricing: Henry Hub, Basis Differentials, and Regional Markets

Introduction

Natural gas pricing is the second critical commodity dimension for energy investment bankers, and in many ways it is more complex than crude oil pricing. While oil is a globally fungible commodity that can be loaded onto tankers and shipped anywhere, natural gas is constrained by pipeline infrastructure and liquefaction capacity. A molecule of gas produced in the Permian Basin cannot easily reach a buyer in Tokyo; it must first flow through gathering systems, processing plants, long-haul pipelines, and potentially an LNG export terminal before it becomes a globally tradeable commodity. This fundamental infrastructure dependence creates regional pricing dynamics, basis differentials, and market structure complexities that directly and materially affect how energy bankers value E&P companies, midstream assets, and power generation facilities.

Understanding natural gas pricing is essential for multiple reasons. First, natural gas represents a growing share of US energy production and is the primary fuel for electricity generation. Second, the rapid ongoing expansion of LNG exports is transforming the US market from an isolated domestic system into a globally connected one, with significant implications for pricing and investment. Third, basis differentials (the price difference between regional hubs and the Henry Hub benchmark) can be larger than the commodity price itself in extreme cases, making them a critical input in every natural gas-related financial model.

Henry Hub, located in Erath, Louisiana, is the pricing point for the most actively traded natural gas futures contract in the world (NYMEX Henry Hub futures). It serves as the reference price for approximately 90% of US natural gas transactions and is increasingly relevant as a global LNG pricing benchmark.

Henry Hub

The primary US natural gas pricing benchmark, physically located at a pipeline interconnection point in Erath, Louisiana. Henry Hub's importance derives from its extensive pipeline connectivity (nine interstate and four intrastate pipelines converge at or near the hub), proximity to natural gas storage facilities, access to both production supply and consumption demand, and a deep, liquid futures market. Natural gas futures traded on the NYMEX use Henry Hub as the delivery point, and the resulting price serves as the benchmark against which all other US natural gas prices are set.

Henry Hub natural gas averaged $2.21 per MMBtu in 2024, the lowest average annual price in inflation-adjusted terms ever recorded. This price depression reflected a combination of record US production (approximately 103 Bcf/d in dry gas terms), mild winter weather that reduced heating demand, and a temporary pause in new LNG export capacity additions. In 2025, Henry Hub rebounded 56% to average $3.52 per MMBtu as LNG exports expanded, data center power demand accelerated natural-gas-fired electricity generation, and producers exercised discipline in drilling programs.

The price recovery illustrates a key dynamic: natural gas pricing is more volatile than crude oil on a percentage basis because the market is more sensitive to short-term supply-demand imbalances. Unlike crude oil, which can be stored relatively easily in tanks and strategic reserves, natural gas storage is limited to underground facilities (depleted reservoirs, salt caverns, aquifers) that have finite injection and withdrawal capacity. This storage constraint means that even modest demand surprises (a cold winter snap, a heat wave driving air conditioning load) can cause sharp price spikes.

The seasonal pattern of gas pricing reflects this storage dynamic. During the "injection season" (April through October), utilities and marketers inject gas into storage, building inventory for winter heating demand. During the "withdrawal season" (November through March), storage is drawn down to meet heating loads. Henry Hub prices typically exhibit a seasonal premium for winter months, with the January-February contracts trading above summer contracts. This seasonal structure, combined with weather uncertainty and storage levels, creates the pricing backdrop against which energy bankers build their gas price assumptions.

US natural gas production reached a record in 2025, with marketed production averaging approximately 118 Bcf/d according to the EIA. The Appalachian region led at 36.6 Bcf/d (31% of total), followed by the Permian at 27.7 Bcf/d (23%) and the Haynesville at 14.9 Bcf/d. This production is consumed across four major demand categories: electricity generation (the largest, at roughly 40 Bcf/d), industrial use (approximately 22 Bcf/d), residential and commercial heating (variable by season, 10-40 Bcf/d), and LNG exports (approximately 14 Bcf/d). The balance between these supply and demand components determines the Henry Hub price level.

Basis Differential (Natural Gas)

The price difference between natural gas at a specific regional hub and the Henry Hub benchmark. A negative basis (discount) means the regional hub trades below Henry Hub, typically because pipeline takeaway capacity from that producing region is constrained. A positive basis (premium) means the regional hub trades above Henry Hub, typically because the consuming region must pay transportation costs to import gas. Basis differentials are a critical input in E&P valuations, midstream investment analysis, and hedging effectiveness evaluation.

Unlike crude oil, where WTI and Brent are relatively similar prices for a globally traded commodity, natural gas prices vary dramatically by geographic location within the US.

Basis differentials arise because natural gas cannot be easily rerouted. Crude oil can be loaded onto tankers and shipped globally; natural gas must move through fixed pipeline infrastructure. When pipeline capacity from a producing region to consuming markets is constrained, the local gas price falls below Henry Hub (a "negative basis" or discount). When pipeline capacity is abundant, the basis differential narrows to approximately the pipeline transportation tariff.

The Major Regional Hubs

Waha Hub (Permian Basin, West Texas) is the pricing point for natural gas produced in the Permian Basin. Waha trades at a chronic and sometimes severe discount to Henry Hub because the Permian generates enormous volumes of associated gas (natural gas produced alongside crude oil) that must compete for limited pipeline takeaway capacity. In 2024-2025, the Permian accounted for approximately 23% of US marketed natural gas production (27.7 Bcf/d in 2025, up 11% year-over-year), and production growth outpaced pipeline additions, pushing Waha prices to steep discounts. In extreme periods, Waha gas prices have turned negative, meaning producers had to pay to dispose of gas because pipeline capacity was full and flaring restrictions prevented burning it at the wellhead.

Dominion South (Appalachian Basin) is the major pricing hub for natural gas produced in the Marcellus and Utica shales of Pennsylvania, West Virginia, and Ohio. Appalachia is the largest gas-producing region in the US (31% of marketed production, approximately 36.6 Bcf/d in 2025), but the region has historically suffered from pipeline takeaway constraints that created wide basis discounts to Henry Hub. The Marcellus Shale, which spans Pennsylvania and West Virginia, is the most prolific gas field in the United States, producing ultra-dry gas (very high methane content with minimal NGLs) at some of the lowest per-unit costs in the world. Despite this cost advantage, Marcellus producers have faced chronic challenges monetizing their gas at fair value because the regional pipeline network was not built to handle the massive production growth that occurred after 2010.

The completion of the Mountain Valley Pipeline in June 2024 provided meaningful relief by adding 2 Bcf/d of southbound takeaway capacity, but Dominion South still trades at a discount reflecting the structural oversupply of gas relative to local demand and the cost of long-haul transportation to consuming markets in the Southeast and Gulf Coast. For energy bankers, the Appalachian basis differential is a critical variable in valuing companies like EQT (the largest US natural gas producer), Range Resources, and Antero Resources, all of which are priced off Appalachian basis points rather than Henry Hub directly.

SoCal Citygate and PG&E Citygate (California) trade at premiums to Henry Hub because California is a net gas importer with limited local production and heavy demand from gas-fired power plants and residential heating. The El Paso Natural Gas pipeline system and Kern River pipeline deliver gas from the Permian and Rocky Mountain regions to California, and the tariff cost plus any capacity constraints translate into premium pricing.

Chicago Citygate is the major hub for Midwest gas consumption, reflecting heating demand in the industrial heartland. Chicago basis is typically a modest premium to Henry Hub, reflecting transportation cost from the Gulf Coast or Midcontinent.

AECO (Alberta, Canada) is the benchmark for Western Canadian natural gas, and it trades at a significant discount to Henry Hub due to the isolated nature of the Alberta gas market. Canadian gas must compete for limited pipeline export capacity to reach US consuming markets, and the TC Energy NOVA Gas Transmission system within Alberta frequently faces maintenance-related constraints that depress local prices. The AECO-Henry Hub differential is particularly relevant for energy bankers at Canadian-focused banks (RBC, BMO, Scotiabank) covering cross-border gas transactions and for midstream companies operating infrastructure that links Canadian supply to US markets.

These basis patterns are not static. Pipeline additions (like Mountain Valley in 2024), LNG export growth, and changes in regional production all shift basis relationships over time. Energy bankers must track basis trends and incorporate forward basis curves into their models rather than assuming historical averages persist.

The most significant structural change in US natural gas pricing over the past decade is the emergence of the US as a major LNG exporter. US LNG export capacity has grown from near zero in 2015 to approximately 14 Bcf/d in 2025, making the US the world's largest LNG exporter. This transformation has profound implications for Henry Hub pricing and basis differentials.

LNG exports create a price floor for Henry Hub. When international gas prices (TTF in Europe, JKM in Asia) are high relative to Henry Hub plus the cost of liquefaction and shipping, LNG exporters increase utilization, pulling more gas out of the domestic market and supporting Henry Hub prices. When international prices are low, export economics weaken, utilization may decline, and more gas remains available for domestic consumption, depressing Henry Hub. This bidirectional linkage means that Henry Hub is no longer purely a domestic benchmark; it is increasingly a globally connected price signal that responds to supply disruptions in Qatar, weather events in Europe, and industrial demand patterns in China and Japan.

LNG pricing mechanics are directly relevant for energy bankers working on LNG infrastructure transactions. Most US LNG contracts use one of two structures. Tolling agreements charge a fixed liquefaction fee (approximately $2.25-3.50 per MMBtu) plus the buyer supplies their own gas (or the contract specifies 115% of Henry Hub as the gas cost). Under this structure, if Henry Hub is $3.50 per MMBtu, the total LNG cost is approximately $3.50 x 1.15 + $3.00 = $7.03 per MMBtu on an FOB (free on board) basis, before shipping costs of $1.00-2.50 per MMBtu depending on the destination. Henry Hub-indexed sale and purchase agreements (SPAs) price the delivered LNG as a fixed percentage of Henry Hub (typically 110-115%) plus a fixed component.

The buyer then sells or consumes the LNG at the destination market price (TTF in Europe, typically $8-15 per MMBtu; JKM in Asia, typically $10-18 per MMBtu), and the margin between the destination price and the all-in US export cost determines profitability. When European TTF spiked above $60 per MMBtu during the 2022 energy crisis, US LNG exporters earned extraordinary margins. Under more normalized conditions, the spread of $3-8 per MMBtu between US export costs and international prices supports continued investment in new liquefaction capacity.

Natural gas pricing feeds into virtually every corner of energy banking work.

In E&P valuations, the gas price assumption (and the applicable basis differential) drives a significant portion of NAV for any company with meaningful gas production. For gas-weighted producers like EQT (the largest US natural gas producer, operating primarily in the Marcellus and Utica shales), Expand Energy (formed from the 2024 merger of Chesapeake Energy and Southwestern Energy to create a combined Haynesville and Marcellus platform), and Comstock Resources (a pure-play Haynesville producer), the gas price is the dominant valuation variable. When Henry Hub moves $0.50 per MMBtu, the equity value of these companies can shift by 15-25% because gas revenue represents 80-95% of their total revenue. For oil-weighted Permian producers, the Waha basis differential on associated gas production can still represent hundreds of millions of dollars in annual cash flow impact, particularly for companies with high gas-to-oil ratios.

In midstream analysis, natural gas gathering and processing volumes are driven by producer activity levels, which are themselves driven by gas prices. A sustained period of low gas prices (like 2024) causes gas-weighted producers to curtail drilling, reducing gathering volumes and processing throughput for connected midstream operators. Conversely, rising gas prices and LNG export demand incentivize drilling in gas-rich basins, boosting midstream utilization and growth capital spending.

In power markets, natural gas is the marginal fuel for electricity generation in most US markets, meaning the gas price sets the clearing price for power during most hours. Natural gas fueled approximately 43% of US electricity generation in 2025, making it the single largest generation source. Higher gas prices translate directly into higher electricity prices, which benefits nuclear and renewable generators (whose fuel costs are zero) and penalizes gas-dependent consumers. The relationship between Henry Hub and spark spreads is fundamental to understanding power sector valuations, and the AI-driven surge in electricity demand is creating a structural tailwind for both gas prices and gas-fired generation capacity values.

In hedging analysis, gas producers hedge their production using instruments referenced to Henry Hub (NYMEX gas futures, swaps, collars). But as with crude oil, the hedge protects against Henry Hub price movements, not against basis differential movements. A Permian producer hedged at $3.50 Henry Hub that sees the Waha basis widen to $2.00 will realize only $1.50 per MMBtu on its hedged production, far below the $3.50 hedge price. This basis risk is a critical consideration in evaluating hedge book quality and is frequently discussed in energy interviews.

The combination of Henry Hub as the headline benchmark, regional basis differentials that create significant pricing variation, LNG export growth that is structurally linking US gas to global markets, and the fundamental role of gas in power generation makes natural gas pricing one of the most analytically rich areas in energy banking. Mastering these pricing dynamics is essential for any energy banker working on gas-weighted E&P valuations, midstream infrastructure transactions, or power sector advisory.