Natural gas price on Apr 30, 2026 at 5pm EDT?

By April 1, 2026, the aggregate operational nameplate export capacity from these projects is projected to be 3.95 Bcf/d. This total capacity will be contributed solely by the Plaquemines LNG Phase 2 and Golden Pass LNG projects, both of which are anticipated to be fully commissioned and commercially operational by the specified deadline. The Rio Grande LNG project is not expected to be commercially operational within this timeframe, and therefore, its capacity is not included in the aggregate total.

Plaquemines LNG Phase 2 and Golden Pass LNG will be fully operational. Plaquemines LNG Phase 2 is expected to be fully operational by April 1, 2026, with production commencing in July 2025 ^[3] and an uprate application filed in March 2026 ^[4]. This phase contributes approximately 1.75 Bcf/d to the export capacity ^[2]. Golden Pass LNG is also anticipated to be fully commissioned and commercially operational by the deadline, having achieved its first LNG production ^[5] and shipped its inaugural cargo ^[6] prior to April 1, 2026. A semi-annual report further confirms its operational status ^[7]. Golden Pass LNG adds approximately 2.2 Bcf/d to the total operational capacity.

Rio Grande LNG will not be operational by April 2026. While commissioning for its first train was eyed for late 2025 ^[8] and a business update provided in Q4 2025 ^[9], full commercial operations are generally anticipated later in 2026 or beyond. Consequently, no operational capacity from the Rio Grande LNG project is included in the aggregate total for April 1, 2026.

Based on their 2025 guidance, top US natural gas producers project modest output growth. The combined average daily production of natural gas and natural gas equivalent for EQT, Chesapeake, Antero, and Coterra is expected to grow by approximately 2.1% in 2025 compared to their 2024 average. Their total average daily production is estimated to increase from approximately 14,421.5 MMcf/d in 2024 to roughly 14,726.5 MMcf/d in 2025. Data for Southwestern Energy was not available in the provided research to include in this combined analysis.

Individual company projections reveal diverse production trends for 2025 among these leading companies. EQT Corporation projects its average daily net production sales volumes to increase from a 2024 midpoint of approximately 5,959 MMcf/d to a 2025 midpoint of approximately 6,164 MMcf/d ^[2]. Chesapeake Energy anticipates its average daily net production to rise from a 2024 midpoint of 3,400 MMcf/d to a 2025 midpoint of 3,550 MMcf/d ^[3]. Antero Resources expects its average daily natural gas production to increase slightly from a 2024 midpoint of 2,237.5 MMcf/d to a 2025 midpoint of 2,262.5 MMcf/d, planning to average approximately two drilling rigs and three completion crews throughout 2025 ^[4]. In contrast, Coterra Energy projects a slight decline in its average daily natural gas production, from a 2024 midpoint of 2,825 MMcf/d to a 2025 midpoint of 2,750 MMcf/d ^[5].

The U.S. Environmental Protection Agency (EPA) has proposed to repeal the greenhouse gas (GHG) emission standards for power plants that were originally promulgated on May 9, 2024. This proposal, made on June 11, 2025, cites significant legal vulnerabilities and economic considerations as reasons for withdrawing the rule ^[1]. The 2024 standards had previously established guidelines for new, modified, reconstructed, and existing fossil fuel-fired electric generating units, including existing gas-fired turbines ^[4].

Consequently, no specific compliance requirements are mandated for existing gas-fired turbines by the end of 2025. Given the ongoing repeal process, which is currently open for public comment and review, the 2024 rule's compliance requirements are not expected to be in effect ^[1]. The EPA indicated that repealing these standards would save Americans over a billion dollars annually ^[3]. Had the 2024 standards remained in effect, they were projected to result in an additional 0.4 GW of existing gas-fired capacity retirements between 2025 and 2039 ^[2].

A sustained WTI crude oil price below $70/barrel will curb Permian natural gas growth. A WTI crude oil price remaining below $70/barrel for the majority of 2025 is anticipated to negatively affect crude oil drilling activity within the Permian Basin ^[1]. This projected decrease in oil drilling would subsequently lead to either dampened growth or a year-over-year decline in associated natural gas production, as natural gas in the region is largely a byproduct of oil extraction ^[1]. Permian Basin operators are reportedly preparing for a challenging period in 2026, with a potential rebound not expected until 2027, suggesting a difficult production environment leading up to and during 2025-2026 ^[4].

The Matterhorn Express is operational, but DeLa Express faces delays. The Matterhorn Express pipeline is already operational, with pipe flows confirming its expansion is live ^[2]. Its ramp-up has been observed, though it has not fully resolved negative Permian price trends, thereby confirming its operational status ^[5]. In contrast, the DeLa Express pipeline is not projected to be fully operational by any near-term stated in-service dates. As of April 2024, the project was still seeking approval from the Federal Energy Regulatory Commission (FERC) and was targeting a launch date in 2028 ^[3]. The DeLa Express is designed to add 690 miles of natural gas takeaway capacity from the Permian Basin to Louisiana ^[6].

The Henry Hub and TTF spread is projected to incentivize US LNG exports. The average price spread between the Henry Hub and Dutch TTF front-month natural gas contracts for 2025 is anticipated to be between $4.00 and $7.00 per MMBtu, a range considered sufficient to support US LNG export economics ^[1]. Towards the end of 2025, Henry Hub prices experienced heightened volatility, while Europe’s TTF faced upward pressure due to cold weather forecasts and inventory drawdowns ^[1]. For early 2026, forecasts suggest Henry Hub could average approximately $4.00-$4.50/MMBtu, with TTF potentially ranging between €25-€30/MWh (or about $8.50-$10.20/MMBtu). This indicates a projected spread of $4.00-$6.20/MMBtu ^[5]. Historically, the TTF-Henry spread has at times significantly tightened, with TTF prices occasionally falling below the full delivered cost of US LNG ^[6].

Combined liquefaction and shipping costs generally range from $4.00 to $6.00/MMBtu. The cost of liquefaction for new capacity is estimated at roughly $3.50/MMBtu ^[7], typically falling between $3.00-$4.00/MMBtu ^[2]. Transatlantic shipping from the US Gulf Coast to Northwest Europe usually costs between $1.00 and $2.00/MMBtu ^[7], ^[2]. Consequently, the total cost for liquefaction and transatlantic shipping is generally $4.00 to $6.00/MMBtu ^[2]. While Atlantic LNG freight rates surged in late 2025, reaching their highest levels since early 2024 due to robust demand and temporary vessel availability constraints ^[8], a substantial number of new LNG carriers are scheduled for delivery in late 2025 and throughout 2026 ^[9]. This expansion of the fleet is expected to gradually alleviate shipping market tightness and could potentially reduce freight rates in the medium term, although strong demand and operational challenges might temper immediate effects ^[9].

EU CBAM will not directly impact LNG import costs through 2026. The EU Carbon Border Adjustment Mechanism (CBAM) will not directly affect LNG import costs in 2025 or 2026, as natural gas (LNG) is not included within its initial scope ^[3], ^[4]. CBAM is structured to apply to specific carbon-intensive goods such as cement, iron and steel, aluminium, fertilizers, electricity, and hydrogen, with full implementation planned for 2026 following a transitional phase that commenced in October 2023 ^[3], ^[4]. While there are ongoing discussions concerning its indirect influence on industrial consumers and energy expenses within the EU, direct carbon pricing on LNG imports via CBAM is not foreseen within the specified timeframe based on current regulations ^[4].