Haynesville production still has upside, while increased southbound gas flows may continue widening regional discounts through the end of 2027

Overview

The report examines Haynesville natural gas along three main dimensions: production, the pipeline network, and prices. Its central conclusion is that current production is already higher than the market generally recognizes and still has upside over the coming quarters. New infrastructure is concentrating gas flows toward the southern United States and LNG export facilities, but supply is temporarily expanding faster than demand and takeaway capacity, so regional basis differentials may widen further through the end of 2027.

Core views

First, Citi believes commonly cited statistics underestimate actual Haynesville production. Its pipeline-by-pipeline analysis not only counts flow points within producing counties but also tracks pipelines outside the production region that receive omitted volumes. On this basis, year-to-date production has already exceeded the previous record of 15.3 bcf/d and approached 16 bcf/d in early May 2026; from November 2025 to July 2026, production rose from approximately 14 bcf/d to 15 bcf/d. The EIA has also repeatedly revised its estimates upward: when the EIA previously reported only 12.2 bcf/d, Citi estimated November 2025 production at approximately 14 bcf/d. The latest STEO figures for November and December 2025 are 13.9 and 14.0 bcf/d, respectively, directionally consistent with Citi's original assessment. Recent production growth has come from both increased utilization of new pipelines and the recovery of flows on legacy pipelines. Combined flows on LEG and NG3 have reached approximately 2.5 bcf/d, with year-to-date average flows of 1.25 and 1.30 bcf/d, respectively, and peak daily utilization rates of 85% and 88%, respectively. LEAP's approximately 2 bcf/d of capacity is operating essentially at full utilization. Compared with approximately 11.5 bcf/d before the expansions, flows on existing pipelines other than LEAP once declined by approximately 1.2 bcf/d, but LEG and NG3 added approximately 2.5 bcf/d, while LEAP Phase 4 contributed another approximately 0.2 bcf/d. From January to June 2026, legacy pipeline flows recovered by approximately 0.5 bcf/d from their average level in October—November 2025, with Gulf Run, Gulf South, and Tiger benefiting the most. This indicates that the new systems are not merely reallocating existing volumes but are also supporting net production growth. At the same time, incremental LEG flows coincided with a 0.3 bcf/d decline in Haynesville volumes received by Enable Gas Transmission, indicating a clear southward shift in flows. The next phase of production growth is linked to forward prices, hedging, and drilling activity. In January 2026, contracts for the fourth quarter of 2026 and the first quarter of 2027 were in the most expensive section of the forward curve, and the price rebound may have prompted producers to lock in prices and expand drilling. The Haynesville natural gas rig count rose from 42 in early January 2026 to 52 in February and then to 58 in May, an initial increase of 10 rigs, or approximately 25%. This pattern resembles the rise in forward prices and rig additions in early 2025, followed by production growth from the end of the third quarter through the fourth quarter of 2025. Citi therefore expects production could rise by another 1—2 bcf/d quarter over quarter in the coming quarters, with the increase potentially concentrated in the fourth quarter of 2026 and the first quarter of 2027 to match seasonal demand and rising LNG exports. However, total production may not increase by approximately 2.5 bcf/d because new wells must also offset natural declines. Over the longer term, data-center loads and LNG feedgas demand could continue incentivizing price-sensitive producers to increase output, but Citi disagrees with the view that Haynesville will inevitably reach its takeaway-capacity limit around 2030. The capacity-limit assumption depends on data centers and LNG terminals operating near full utilization. The report judges that LNG demand in East Asia and Europe could flatten or decline after peaking, while a global LNG surplus could force the United States to curtail exports. Conditions in the Middle East may increase contracting for US LNG, but whether the contracted volumes are ultimately lifted will still depend on future prices. Consequently, more moderate LNG offtake and prices could slow longer-term production growth. The report also notes that the seasonal cycle in which cold winters lift the forward curve, encourage hedging, increase rig counts, and produce higher output by year-end could recur, while the reverse process is equally possible. Pipeline analysis shows that Haynesville gas is transported mainly through a two-step southbound route: it first enters Gillis Hub in Louisiana through systems including LEAP, LEG, NG3, Gulf Run, and Acadian, and is then delivered through interconnected pipelines to Gulf Coast LNG terminals and other southern demand centers. Current capacity into Gillis Hub is approximately 8.3 bcf/d. LEG, NG3, and Acadian are operating at roughly 70% utilization, while LEAP has approximately 10% of its capacity remaining, leaving an estimated approximately 1.3 bcf/d of total spare capacity. Gulf Run has available capacity but does not connect directly to Gillis Hub, instead providing alternative routes through Golden Pass LNG and Trunkline. Planned incremental capacity into Gillis Hub totals approximately 4.5 bcf/d. The Pelican pipeline is scheduled to come online at the end of 2027 with capacity of 2.5 bcf/d. LEAP Phase 5 is planned to add 0.2 bcf/d in the second half of 2028, bringing LEAP's total capacity to 2.3 bcf/d. Gulf South Texas Gateway is scheduled to come online in the fourth quarter of 2028 with capacity of 1.8 bcf/d. Planned incremental capacity downstream of Gillis Hub to LNG facilities is approximately 7.0 bcf/d: Gillis Access Phase 1 is expected to add 1.4 bcf/d in December 2026, and Phase 2 is expected to add 0.5 bcf/d at the end of 2027. Port Arthur Pipeline Louisiana Connector is scheduled to come online in January 2027 with capacity of 2.0 bcf/d, while Driftwood Pipeline Line 200 is scheduled to come online in the second quarter of 2028 with capacity of 3.1 bcf/d. Citi therefore believes LNG demand in southern Louisiana will remain the primary outlet for Haynesville growth over the next several years. Southeast Texas faces stronger competition from Permian Basin gas supplies, and currently only approximately 0.9 bcf/d of Haynesville natural gas enters the Texas market. Blackcomb is scheduled to come online in the third quarter of 2026 with capacity of 2.5 bcf/d. Hugh Brinson Phase 1 is expected to reach approximately 1.5 bcf/d in September 2026, while Phase 2 will increase capacity to approximately 2.2 bcf/d in the first quarter of 2027. Eiger Express is scheduled to come online in mid-2028 with capacity of approximately 3.7 bcf/d. These projects will deliver more Permian Basin natural gas to South Texas and the Gulf Coast, reducing the market available to Haynesville. Natural gas from parts of the Midland Basin can have nitrogen content of 5%—8%, while LNG facilities typically prefer feedgas with nitrogen content of approximately 1% or less, and some LNG pipelines impose limits of approximately 2.0%—2.6 mol%. Haynesville's low-nitrogen gas can therefore be used for blending. However, nitrogen can be addressed through nitrogen-removal units, blending, or upstream processing. If Permian gas is sufficiently inexpensive, the associated processing costs can be absorbed, so Citi believes the nitrogen issue is real but insufficient to fundamentally prevent competition. The US Southeast is another important outlet. In early July, restrictions at Transco Compressor Station 160 reduced southbound flows from the Northeast to approximately 80% of normal levels, prompting the Southeast to turn to Gulf Coast supply. Flows at Transco Station 90 in Alabama rose from approximately 2.3 bcf/d at the end of June to 3.5—3.6 bcf/d. The disruption at Transco Station 70 on August 15, 2026 produced a similar tightening effect and raised Southeast basis differentials, demonstrating that Haynesville can play a balancing role when Northeast gas is constrained. However, Transco's 1.6 bcf/d Southeast Supply Enhancement Project is expected to come online in the third quarter of 2027, after which Northeast gas may recapture part of Haynesville's share in the Southeast market, pushing more Haynesville volumes southward. Regarding prices, at least 50% of Haynesville natural gas currently supports LNG exports, and Carthage Hub's sensitivity to LNG export volumes and demand will continue to increase. The year-to-date widening of the basis has primarily resulted from higher regional production following the commissioning of new pipelines, without corresponding growth in local demand or deliveries to external regions. Carthage's historical discount to Henry Hub is typically $0.20—0.40/MMBtu, but it has recently widened to approximately $0.30—0.50/MMBtu and is sometimes wider, averaging approximately $0.10/MMBtu wider than before LEG and NG3 came online. Citi expects strong production, higher pipeline utilization, and elevated inventories in 2027 to cause the Carthage, Columbia Gulf Mainline, and NGPL Texok basis differentials to widen further until Pelican comes online at the end of 2027, even as LNG offtake increases over the same period. Regional prices are also jointly influenced by Northeast gas, Permian gas, local data-center demand, global LNG fundamentals, remaining pipeline capacity, and producers' price response. Stronger LNG pull and local demand help narrow basis differentials, while maintenance and other operational flow restrictions can cause short-term jumps in spreads; overall inventory levels dominate absolute prices. Citi combines production, pipeline capacity, LNG demand pull, and inventory modeling, while using both all spot prices and capped spot prices to reduce the effect of a small number of anomalous prices caused by extreme weather or unexpected maintenance on weekly, monthly, and quarterly averages. Ultimately, stronger Haynesville and Permian Basin production supports its forecast of an average Henry Hub price of $2.8/MMBtu in 2027. As US LNG exports increase and a global LNG surplus potentially emerges, the report also expects correlations among Henry Hub, Asian JKM, and European TTF to strengthen.

Analysis framework

The report first re-estimates current Haynesville production using pipeline-by-pipeline flow data both inside and outside the production region and cross-validates the results against successive EIA revisions. It then uses the forward curve, producers' hedging incentives, changes in the rig count, and the historical pattern from 2025 to infer the timing of near-term production growth. The infrastructure section examines, pipeline by pipeline, the existing capacity, utilization rates, projects under construction, and competing gas supplies across three takeaway routes: southern Louisiana, southeast Texas, and the US Southeast. The pricing section then incorporates production, pipeline capacity, LNG demand, local demand, and inventories into regional absolute-price and basis models, using capped spot prices to reduce the impact of extreme events on average prices.

Methodology notes

• (Method outside the taxonomy)

  Pipeline-by-pipeline flow collection and supplementation of flows outside the production region

  The report not only aggregates flow points within gas-producing counties but also tracks volumes received outside the production region along each pipeline to reduce omissions and re-estimate actual production, and then uses revised EIA data to validate the direction.

• Industry analysis frameworkSupply-demand framework

  Balance among regional natural gas supply, demand, and takeaway capacity

  The report compares production, local demand, LNG offtake, inventories, and remaining pipeline capacity. When supply grows faster than demand and takeaway capacity, the regional price discount to Henry Hub widens.

• Industry analysis frameworkUpstream-midstream-downstream value-chain transmission

  Pipeline transmission from gas fields to hubs and LNG terminals

  The report tracks gas flows from the Haynesville fields through the Gillis and Carthage hubs to Gulf Coast LNG terminals, explaining how infrastructure changes reshape regional allocation and pricing.

• (Method outside the taxonomy)

  Forward price—hedging—rig count—production response chain

  The report argues that higher forward prices encourage producers to hedge and add rigs, with drilling activity translating into production after a time lag, and uses a similar pattern from 2025 to support its projections for 2026—2027.

• (Method outside the taxonomy)

  Capped spot-price modeling

  The price model uses both all actual spot prices and capped prices to limit the impact of a small number of outliers caused by extreme weather or unexpected pipeline maintenance on weekly, monthly, and quarterly average prices.

Asset mapping & comparison

Structured mapping from thesis to named assets (strengths, weaknesses, peers, risks).

• Haynesville natural gas

  The report expects current production to be underestimated and believes it could still increase by 1—2 bcf/d quarter over quarter in the coming quarters.

  Strengths

  Proximity to Henry Hub and most US LNG export terminals, active construction of southbound pipelines, and producers' ability to adjust drilling rapidly in response to forward prices.

  Weaknesses

  New wells must offset natural declines, while regional supply growth may outpace local demand and the expansion of takeaway capacity.

  Comparison

  Competes with Northeast gas in the Southeast market and with Permian Basin gas in Texas and Louisiana.

  Risks

  Weaker-than-expected global LNG offtake, increased competing supplies, or lower prices could slow long-term production growth.

• Carthage Hub natural gas basis

  Haynesville production growth and the restructuring of southbound flows have widened Carthage's discount to Henry Hub.

  Strengths

  Its connectivity to LNG exports and southern demand centers continues to improve.

  Weaknesses

  Regional supply is growing faster than local demand and incremental takeaway capacity, making the basis sensitive to high pipeline utilization.

  Comparison

  The historical discount is typically $0.20—0.40/MMBtu and has recently widened to approximately $0.30—0.50/MMBtu.

  Risks

  Weak LNG pull, high inventories, and competition from Northeast and Permian gas could all widen the discount further.

• Henry Hub natural gas

  Stronger Haynesville and Permian Basin production supports the report's forecast of an average price of $2.8/MMBtu in 2027.

  Strengths

  As US LNG exports increase, its influence on global natural gas pricing is expected to strengthen.

  Weaknesses

  Production growth and high inventories place pressure on absolute prices.

  Comparison

  The report expects Henry Hub's price correlations with Asian JKM and European TTF to strengthen.

  Risks

  Weather, inventories, LNG export volumes, and unexpected pipeline maintenance could cause substantial price volatility.

Key data

• Recent Haynesville production peakNearly 16 bcf/dIn early May 2026, surpassing the previous record of 15.3 bcf/d
• Production increase over the coming quarters1—2 bcf/dThe report's projected quarter-over-quarter increase
• Change in rig count42 rigs→52 rigs→58 rigsCorresponding to early January, February, and May 2026, respectively
• Combined LEG and NG3 flowsApproximately 2.5 bcf/dYear-to-date average flows of 1.25 and 1.30 bcf/d, respectively
• Peak LEG and NG3 utilization rates85% and 88%Peak daily levels for the two new systems
• Existing Haynesville-to-Gillis Hub capacityApproximately 8.3 bcf/dAn estimated approximately 1.3 bcf/d of capacity remains available
• Planned incremental capacity into Gillis HubApproximately 4.5 bcf/dIncluding Pelican, LEAP Phase 5, and Gulf South Texas Gateway
• Planned incremental downstream capacity from Gillis HubApproximately 7.0 bcf/dPrimarily connecting to Gulf Coast LNG facilities
• Haynesville gas volumes entering the Texas marketApproximately 0.9 bcf/dFacing competition from Permian Basin and Eagle Ford supplies
• Share of LNG-related gas volumesAt least 50%The current share of Haynesville natural gas used to support LNG exports
• Historical Carthage basisDiscount of $0.20—0.40/MMBtuThe typical range relative to Henry Hub
• Recent Carthage basisDiscount of approximately $0.30—0.50/MMBtuSometimes wider, averaging approximately $0.10/MMBtu wider than before LEG and NG3 came online
• Transco SSEP capacity1.6 bcf/dExpected to come online in the third quarter of 2027
• Natural gas nitrogen content in parts of the Permian5%—8%LNG facilities typically prefer feedgas with nitrogen content of approximately 1% or less
• Forecast average Henry Hub price in 2027$2.8/MMBtuSupported by stronger Haynesville and Permian Basin production

Impact & implications

The report believes Haynesville's production-growth capacity is stronger than the market recognizes and that southern Louisiana will become the most important incremental outlet. However, new production may initially outpace the full realization of demand and pipeline capacity, widening the discounts of hubs such as Carthage relative to Henry Hub. Over the medium to long term, flows will become more concentrated toward LNG terminals while facing competition from Northeast and Permian gas. If global LNG demand is weaker than expected, US exports and longer-term Haynesville production growth could slow. The rising share of US LNG exports also means that price linkages among Henry Hub, JKM, and TTF will become tighter.

Risks

• Global LNG demand growth could be weaker than expected, resulting in reduced US LNG exports and slower long-term Haynesville production growth.
• After Transco SSEP comes online, Northeast natural gas may regain market share in the US Southeast.
• New Permian Basin pipelines will deliver more low-cost natural gas to East Texas and Louisiana, intensifying competition.
• Unexpected pipeline maintenance, operational flow restrictions, and extreme temperatures could trigger sharp volatility in regional spot prices and basis differentials.
• The higher nitrogen content of Permian natural gas will increase nitrogen-removal, processing, and blending costs, but low-cost gas supplies may absorb these costs.

What to watch

• Track the Haynesville rig count and whether production can achieve quarter-over-quarter growth of 1—2 bcf/d in the fourth quarter of 2026 and the first quarter of 2027.
• Monitor utilization rates and remaining takeaway capacity on LEG, NG3, LEAP, and legacy pipelines.
• Watch the commissioning schedules of Gillis Access, Pelican, Port Arthur Connector, Driftwood Line 200, and other projects.
• Track the impact of LNG offtake, data-center demand, and US natural gas inventories on regional supply-demand balances.
• Monitor changes in the market shares of Northeast, Permian, and Haynesville gas after Transco SSEP and new Permian Basin pipelines come online.
• Observe whether the Carthage, Columbia Gulf Mainline, and NGPL Texok basis differentials to Henry Hub continue widening through the end of 2027.