Natural gas price on Apr 16, 2026 at 5pm EDT?

Specific natural gas storage projections from EIA's April 2026 STEO are unavailable. The U.S. Energy Information Administration's (EIA) early April 2026 Short-Term Energy Outlook (STEO) does not contain specific projections for the end-of-March 2026 natural gas storage level or a comparison of this figure to the 5-year average inventory for the end of the withdrawal season within the provided web research results.

Provided web research results lacked specific EIA projection data. While several URLs referencing the EIA's Short-Term Energy Outlook pages ^[1] were identified, and there were mentions of an April 2026 outlook ^[2] and a storage report ^[3], the detailed content or specific data points from these sources were not present in the 'Web Research Results' section. Consequently, it is not possible to extract the precise figures for the projected end-of-March 2026 natural gas storage level or its comparison to the 5-year average based on the information provided.

By Q1 2026, U.S. LNG export capacity is projected to substantially increase. The total commissioned and operational LNG export capacity in the United States is expected to reach approximately 24.5 Bcf/d by Q1 2026 ^[1]. This significant expansion includes over 21 Bcf/d of new liquefaction capacity anticipated to come online between 2024 and 2028, representing a considerable boost from prior years ^[2]. For context, U.S. LNG exports averaged 11.6 Bcf/d in 2023 and were projected to rise further in 2024 and 2025 ^[3].

Major terminals like Plaquemines LNG are expanding capacity in phases leading into 2026. Plaquemines LNG Phase 1 is scheduled to begin its first train startup in Q4 2024, with subsequent trains planned for 2025 and 2026. Similarly, Corpus Christi Stage III anticipates its first train in 2025, followed by others in 2026 and 2027 ^[4]. While specific average utilization rates for these individual nascent projects by Q1 2026 are not available in the provided sources, overall U.S. liquefaction facilities operated at an average utilization rate of 85% in 2023 ^[2].

Major energy firms forecast the Permian Basin to be the primary natural gas growth driver. Major energy analytics firms and the U.S. Energy Information Administration (EIA) generally anticipate the Permian Basin to be the primary driver of natural gas supply changes for full-year 2025 and leading into 2026. The EIA specifically projects that the Permian Basin will lead natural gas output growth in 2026 ^[1]. Wood Mackenzie highlights ongoing build momentum in Permian Basin gas infrastructure ^[3], and Rystad Energy identifies the Permian as a key driver shaping the US onshore industry outlook heading into 2026 due to gas strength ^[4].

Haynesville contributes substantially, but Permian growth leadership is expected until 2027. The Haynesville shale is also expected to contribute significantly to natural gas production growth, with Wood Mackenzie noting that US shale gas, overall, is experiencing a resurgence driven by new demand signals ^[5]. However, the EIA forecasts that the Haynesville will overtake the Permian in natural gas growth only in 2027, particularly as Henry Hub prices are projected to top $4 ^[2]. This suggests that for 2025 and through 2026, the Permian Basin is anticipated to maintain its leading position in terms of natural gas production growth ^[2]. Overall, the EIA projects U.S. natural gas production to reach record highs in both 2026 and 2027 ^[6].

Based on EIA Form 860 and 860M data, ERCOT and PJM expect substantial renewable and storage additions in 2025. A significant amount of utility-scale solar and battery storage capacity is scheduled to come online in these territories. In the ERCOT region, Texas is expected to add 11.2 gigawatts (GW) of utility-scale solar capacity ^[1]. ERCOT is also projected to lead the country in new utility-scale battery storage capacity, with 6.1 GW planned, representing 45% of the total U.S. additions ^[1]. For the PJM region, planned additions for 2025 include 2.7 GW of utility-scale solar and 1.6 GW of battery storage ^[1].

These additions will likely reduce natural gas demand in 2026. This projected increase in solar and battery storage capacity is anticipated to impact natural gas demand for power generation, particularly during the shoulder months of 2026. The EIA anticipates that this growth will displace some natural gas-fired generation ^[1]. Specifically, this displacement is most likely to occur during the middle of the day when solar output is at its highest. Additionally, battery storage systems will be utilized to discharge power during evening peaks or shoulder periods, further contributing to a reduction in the need for natural gas generation during these times ^[1].

Weather models forecast above-average temperatures and CDDs for early April. Forecast models, including GFS-based outlooks from NOAA and ECMWF (AIFS ENS), anticipate warmer than seasonal averages for the first two weeks of April 2026 across key demand centers in the southern United States ^[2]. This projection is reinforced by the NOAA Climate Prediction Center's 8 to 14-day outlook and its monthly outlook, both supporting above-average temperatures in the southern and southeastern U.S. ^[2]. Consequently, above-normal Cooling Degree Days (CDDs) are expected for the first half of April 2026 in these regions ^[1].

Elevated cooling demand will likely delay initial seasonal gas storage injections. The prediction of above-normal CDDs in early April 2026 suggests an earlier and potentially stronger onset of cooling demand than typically observed at the start of the shoulder season ^[1]. This increase in demand is expected to drive higher natural gas consumption for electricity generation in the southern U.S., thereby consuming a larger portion of available gas supplies ^[3]. As a result, this elevated cooling demand is projected to reduce the amount of natural gas available for injection into storage, potentially delaying the timing or decreasing the strength of the first significant injection for the season ^[3].