The U.S. LNG Pie Is Big Today

How Haynesville Gas Captures Value Through U.S. LNG Exports 

A cost-stack analysis from the Louisiana Haynesville wellhead to Rotterdam-Netherlands 

$6.60/MMBtu modeled delivered cost  |  $28.22/MMBtu TTF  |  $21.62/MMBtu residual 

The economics of producing natural gas in the Haynesville Shale and ultimately selling that energy into Europe involve far more than simply comparing Henry Hub with the Dutch TTF price. Between the wellhead in Louisiana or East Texas and a regasified LNG molecule in Europe are multiple slices of cost: regional gas basis, gathering and pipeline transportation, liquefaction, ocean freight, vessel fuel, boil-off and port costs. 

Yet when those costs are stacked against today’s European forward prices, the economics remain striking. 

Based on Trio's October 20, 2026 forward-price analysis, estimated U.S. Gulf Coast LNG delivered into the Rotterdam (Netherlands) market costs about $6.60/MMBtu for November 2026 delivery, compared with a TTF forward price of $28.22/MMBtu. The resulting modeled netback is approximately $21.62/MMBtu. 

That extraordinary spread helps explain why the Haynesville shale has become such a strategically important source of incremental natural gas supply for the Gulf Coast LNG industry and why production out of that geographically advantaged area has grown recently. 

It Starts With the Molecule 

The first piece of the cost stack is the natural gas itself. 

The model uses November 2026 Henry Hub futures of $2.986/MMBtu. But an eastern Haynesville producer does not necessarily receive Henry Hub. The model uses Columbia Gulf Mainline as a western-Louisiana Haynesville basis proxy, with November basis of -$0.404/MMBtu. This implies a regional gas value of approximately $2.582/MMBtu. 

That is the first important lesson in LNG economics: a Henry Hub price is not necessarily a Haynesville wellhead price. 

Across the November 2026 through December 2028 period, Columbia Gulf Mainline basis remains negative to Henry Hub in every listed month, ranging from -$0.137 to -$0.419/MMBtu. For the producer, the first slice of the LNG pie is simply achieving an adequate regional price for the underlying gas. 

Then the Gas Has to Get to the LNG Plant 

A molecule sitting in the Haynesville has little international value until infrastructure moves it toward Gulf Coast demand. The model therefore adds a combined estimate for gathering and Gulf Run pipeline capacity, commodity charges and fuel. 

For November 2026, that component is approximately $0.452/MMBtu. Using the November assumptions, the Haynesville regional gas value of $2.582 plus gathering and transportation of $0.452 produces an estimated cost of about $3.03/MMBtu entering the liquefaction stage. 

The cost of natural gas at the wellhead in northwestern Louisiana is not the cost of feedgas at the LNG terminal. Pipeline capacity, gathering and fuel consumed moving the gas each take a slice before the molecule becomes LNG. 

Liquefaction Is the Biggest Incremental Slice 

Once pipeline gas reaches the Gulf Coast LNG facility, ~10-12% of the gas is used in the LNG facility and supercooled liquefaction process itself before it can be placed aboard an LNG vessel. Actual costs vary by facility based on process and setup, but the model assumes $3.00/MMBtu for liquefaction throughout the forward period. 

For November 2026, that lifts the modeled cost from approximately $3.03/MMBtu entering the LNG stage to approximately $6.03/MMBtu before ocean transportation. Under these assumptions, liquefaction is the largest incremental cost between the Haynesville and Europe. 

Contract structure is therefore crucial. Depending on who owns or contracts for liquefaction capacity, the international price exposure does not necessarily accrue to the upstream producer. A producer selling gas at or near the plant gate may monetize a domestic gas price, while an entity controlling liquefaction capacity and LNG marketing can potentially capture a different portion of the value chain. 

Then Comes the Surprisingly Small Atlantic Crossing 

Moving LNG thousands of miles across the Atlantic sounds as if it should be one of the largest costs. In the current model, it is not.  Due to a the current high commodity price of LNG in Europe, the backwardated pricing which is disincentivizing buying and storing gas and the current oversupply of LNG vessels that are avoiding the Strait of Hormuz, LNG vessel daily rates are very soft.   

The model estimates a 23-day round-trip U.S. Gulf Coast-to-Rotterdam shipping cycle at $0.57/MMBtu, consisting of: 

• Vessel charter: $0.30/MMBtu 
• Propulsion and fuel: $0.07/MMBtu 
• Economic value of boil-off: $0.15/MMBtu 
• Port and miscellaneous costs: $0.05/MMBtu 

Under the assumptions, liquefaction costs more than five times as much as the ocean transportation component. The Atlantic may be physically enormous, but in the current cost stack it represents a relatively small economic distance between Louisiana and Northwest Europe. 

Putting the Entire November Cargo Together 

The final $21.62/MMBtu should not automatically be called producer profit. It is better understood as a modeled residual value or margin across the value chain. Who captures that value depends on the contracts for gas supply, pipeline capacity, liquefaction, LNG offtake, shipping and ultimate sales agreement. 

The Forward Curve Says the Opportunity Shrinks, but Does Not Disappear 

The more revealing result is not only November’s massive $21.62/MMBtu netback, but what happens farther out. The model shows the estimated Rotterdam netback declining as TTF falls and U.S. gas costs increase in the forward period. 

Future pricing at the Henry Hub is in contango (prices are higher as time progresses) while TTF prices are backwardated (prices fall as time progresses). Both squeeze the payback of Haynesville based production as the source of LNG to Europe.  The pie has not disappeared, but it is much smaller in the future based on current forward pricing. 

That Is Where Haynesville Production Economics Matter 

When international LNG margins are enormous, the system has a strong economic incentive to source Haynesville gas and move it toward export facilities. The underlying producer, however, still needs a sufficient domestic realization to drill the next Haynesville well. 

A stronger Henry Hub price benefits the producer but raises the feedgas cost of the LNG exporter. A weaker Haynesville basis reduces producer realization but can lower the acquisition cost for a buyer capable of moving the gas south toward LNG export sites. Higher TTF prices expand the total pool of value available within the chain. 

The value chain can be viewed as a series of slices: 

• The upstream producer is paid for the molecule. 
• The gatherer and pipeline are paid to move it. 
• The liquefaction facility is paid to turn it into LNG. 
• The shipowner or charterer is paid to cross the Atlantic. 
• The LNG marketer or capacity holder attempts to monetize the remaining international spread, keeping or giving the remaining opportunity or risk within the terms of the negotiated offtake agreement.  

The Bottom Line  

The October 20, 2026 forward curves make the headline dramatic: a modeled November LNG delivered cost of roughly $6.60/MMBtu against $28.22/MMBtu TTF leaves about $21.62/MMBtu of residual value. 

But the more durable story is what sits underneath that number. Haynesville LNG economics are a chain of individual margins. The producer, gatherer, pipeline, liquefaction facility, shipowner, international marketer, each requiring compensation. Some costs are tied to commodity prices; others depend on long-term contractual capacity, supply and demand for LNG vessels will increase or decrease the slice to deliver gas to Europe while the price structure of the LNG offtake itself plays a role in which participant along the LNG path incurs additional compensation or risk as wholesale price differentials move. 

Consequently, the strategic value of controlling more of the chain becomes obvious when international spreads are very large. The opportunity is not simply to produce more natural gas. It is to connect the molecule economically from the Haynesville wellhead to the international customer. 

Today, the European price is large enough that the pie can comfortably accommodate those slices. By 2028, the same model shows a much tighter environment. 

The question is not simply whether there is a spread between Henry Hub and TTF. It is whether that spread is large enough to pay every participant between the Haynesville wellhead and Rotterdam into the future, while still leaving enough value to justify producing, liquefaction, shipping and marketing the marginal molecule to a European market that is currently priced at four year highs. 

Source and Methodology Note 

Source: “US Gulf Coast LNG Netback to Rotterdam Netherlands model_10-20-2026” authored by Jeff Bolyard. All forward prices, basis values, cost assumptions and modeled netbacks cited in this article come from that model and were aggregated and analyzed by Trio from multiple sources including Bloomberg, ICE, NGI, NYMEX, Gulf Run Pipeline, and other publicly available information as of October 20, 2026. 

The modeled netback is presented as residual value across the chain, not as producer profit. Actual economics depend on contract terms, capacity ownership, facility utilization, fuel use, shipping arrangements, taxes and other costs that may not be represented in the model. 

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