Market Spoke, Hub Evolved: US NatGas Eyes International Prices

Henry Hub has been the default pricing mechanism for U.S. natural gas for more than three decades.

However, the booming overseas LNG market is starting to move pricing considerations well beyond the Gulf Coast. Industry analysts have noted a shift in LNG pricing toward a multipolar model.

Some U.S. E&P companies have shifted part of their natural gas pricing agreements with LNG traders away from domestic Henry Hub prices to international pricing benchmarks in Europe and Asia, or preferred a crude-based Brent index, according to a study published by Fitch Ratings in August.

The LNG industry has entered a transitional phase, where contract terms reflect a fragmented market of competing companies and international buyers with different needs and expectations.

Producers in the U.S. that are able to offer flexible pricing linked to the Japan Korea Marker (JKM) in Asia, the Title Transfer Facility (TTF) in Europe, or hybrid models will be in a strong position to capture future demand growth, analysts said.

“Henry Hub is not going away, but it’s no longer the default,” said Jason Feer, global head of business intelligence at Poten & Partners, during a recent seminar. “Buyers now want pricing optionality and risk alignment.”

At the HH

Trading natural gas as a commodity is relatively new to the industry. Through the 1980s, producers sold natural gas through long-term, life-of-lease contracts to pipelines at prices regulated by the government.

In 1985, the Federal Energy Regulatory Commission (FERC) issued Order 436, creating “open access” to pipelines, as part of an overall deregulatory movement during the Reagan administration. The order allowed pipeline owners to operate solely as transporters of natural gas, meaning producers could find a spot market price. The act resulted in the first appearance of natural gas marketers, according to analytics firm RBN.

It took five years for the market to catch up with the other sectors of the petrochemical industry. Crude oil and heating oil futures had been involved in futures trading for years on the NYMEX. Before natural gas futures could step up, a nationally relevant price point was needed.

Henry Hub, built in the 1950s, is located near Erath, Louisiana. The area is a natural crossroads for pipelines delivering to the Gulf of Mexico. The pipeline hub connects 10 intra- and interstate pipelines, and almost never experienced the service outages that could result in a supply squeeze.

The NYMEX made the Henry Hub the standard delivery point for futures contracts in the 1990s. RBN Energy called it the world’s best-known location for trading natural gas.

Transition

Since then, Henry Hub has served as the cornerstone for U.S. natural gas market pricing. With the appearance of the U.S. LNG export sector in 2016, the hub has also served as the benchmark for U.S. LNG exports.

Showing the strength of U.S. supply, the benchmark offered buyers simplicity and historically low prices. The U.S. natural gas price has consistently remained below prices in Europe and Asia, the two primary global markets, especially since 2021.

Following Russia’s invasion of Ukraine in February 2022, the price of European LNG soared to $54.16/MMBtu in August 2022 and the price in Asia reached $69.98/MMBtu, while the price in the U.S. actually fell from the prior month to $11.19/MMBtu, according to the Federal Reserve Bank of St. Louis.

Since then, U.S. LNG prices have never risen above the Asian and European prices. In February 2025, the U.S. price was at $7.88/MMBtu, the EU price was $15.33/MMBtu and the Asian price was $14.72/MMBtu.

Henry Hub has played a major role in the growth of the U.S. LNG industry. Producers in Texas and Louisiana leveraged the hub to offer competitively priced cargoes to global buyers, securing the long-term offtake agreements that were essential to finance the projects that boosted U.S. export capacity.

However, as the global market matures and supply-demand dynamics vary widely by region, Henry Hub pricing has started to show its limitations, Feer said.

Split markets, rising prices

Several converging factors have spurred producers and buyers to reconsider their reliance on Henry Hub-indexed deals.

Independent natural gas producers are leading the way. Those producers have been largely shut out of the LNG export boom, East Daley wrote in an analysis.

Global utilities and commodity traders took most of the capacity in U.S. LNG projects during the first stage of development. While LNG exports expanded U.S. gas demand, most E&Ps saw no exposure to higher overseas prices.

That dynamic began to change after Cheniere Energy commercialized its Corpus Christi LNG project. Cheniere used integrated production marketing agreements (IPMs) to sign up producers to take capacity in its Stage 3 expansion at Corpus Christi.

Under the IPMs, producers supply gas to the Corpus Christi terminal and receive a price indexed to overseas indexes, after deducting fixed fees for liquefaction, shipping and regasification fees. Cheniere Marketing owns the LNG and is responsible for selling cargoes abroad.

On the buyer’s side, global LNG and gas price spreads have remained wide and led producers and buyers to seek pricing mechanisms that better reflect regional costs. In February 2024, for instance, Mediterranean spot LNG prices reached a high of $13.84/MMBtu, according to Standard & Poor’s. The Henry Hub price at the time remained below $2/MMBtu for most of the month.

That disconnect led customers to seek more stability.

“Spot LNG prices in the European and Asian markets have maintained a significant premium to U.S. HH prices in recent years, but they tend to be more volatile,” the Fitch Ratings report said.

Meanwhile, the U.S. is months away from what some analysts see as an impending supply problem with natural gas. While two new LNG facilities (Plaquemines and Corpus Christi 3) ramp up their production, two new North American facilities—Golden Pass and LNG Canada—are expected to begin operations in the coming months.

Fitch estimated North American LNG production capacity would double from 2024 levels before 2030, resulting in a tightened spread among North American, Asian and European benchmarks.

In the tech sector, companies are rapidly attempting to build gas-fired generators for an exploding power demand for AI data centers.

All of the demand is likely to strain domestic supply and drive up Henry Hub prices. The expansion of U.S. LNG export capacity is expected to place increasing strain on the domestic gas supply. This, in turn, is driving up Henry Hub forward prices. The futures mark sat at $3.72/MMBtu on May 12. The Bank of America Global Research Group predicted prices would surpass $4.50/MMBtu by the end of 2025.

As producers factor in rising feedgas costs, some may seek to renegotiate existing contracts. Buyers could therefore favor using TTF and JKM price points over the long term.

Market education

Buyers—especially in Asia—are becoming more sophisticated in risk management, said Kit Wong of Poten & Partners during a seminar.

After the U.S. slapped trading sanctions on China, the country stopped importing LNG, opting to sell it on the international spot market for a profit and relying on China’s current power infrastructure for energy.

However, companies are also setting up more sophisticated ways to price LNG, Fitch said.

Some large utilities and trading firms are setting up pricing mechanisms that reflect real-time market dynamics. In some recent contracts, hybrid pricing has emerged, blending several price points instead of a single reliance on the Henry Hub to balance exposure to U.S. and regional markets, said Feer.

In 2024, Woodside and Taiwan’s national oil and gas company, CPC Corp., signed a supply contract that included JKM benchmarks for annual sales of 6 million tonnes per year (mtpa) of LNG, S&P reported. Energy companies in general do not publicly disclose their pricing structures.

However, analysts have noted that hybrid pricing has been a trend since mid-2023 in contract negotiations as investment strategies among producers vying for market share in Asia and Europe.

Pricing model types

While the Henry Hub remains active, three other types of pricing models have become favored, according to S&P.

JKM and TTF have become one method in new term agreements, according to S&P. JKM and TTF prices offer a regional tie to local market conditions—especially useful in volatile periods.

Cheniere Energy signed a contract pegged partially to the TTF in 2023 with ARC Resources.

In regions in which oil-indexation has played a role, some Southeast Asian buyers continue to favor Brent-linked LNG deals, viewing them as a hedge against gas-specific volatility. Feer said Brent-indexed pricing makes sense for buyers looking for a shorter-term contract.

“One of the things we’ve seen is the development of Brent as a more flexible benchmark,” Feer said. “There’s so much Brent-related volume because of expiring contracts and because of the ramp-up of Qatari volumes.

“If you’re looking for a three-year contract, five-year contract, seven-year contract, that is most likely available on a Brent-related basis.”

Wood Mackenzie noted that Brent-related LNG projects were “back in vogue” as early as 2023. In 2024, most of the LNG contracts signed were Brent-related, Feer said.

A changing market

In February 2024, EOG Resources signed an agreement with Vitol indexed to Brent crude oil for the next 10 years. The contract begins in 2027, according to East Daley Analytics.

Earlier that same February, Chesapeake entered a 20-year agreement with Delfin LNG and energy trader Gunvor in support of Delfin’s deepwater project in the Gulf of Mexico. Chesapeake will buy 0.5 mtpa of LNG from Delfin LNG and deliver it to Gunvor for a price linked to JKM.

The shift has far-reaching consequences for both sellers and buyers.

With multiple price points in play, contract structures are likely to become more complex. Legal teams and risk analysts must manage price exposure to two or more markets—potentially increasing hedging costs.

The contracts will also become less uniform, meaning individual market transactions will be more difficult for analysts to track, according to Fitch Ratings.