Natural Gas Prices Extend Slide Ahead of Expiration Amid Surging Storage Surplus
This week, the May Henry Hub contract settled 14c or 7.8% lower to $1.61/MMbtu. The May contract expired today, with June now becoming the prompt month contract. The rest of the curve was little changed, with Winter ‘24/’25 down 5c to $3.41/MMbtu, and the Summer ’25 strip up 1c to $3.35/MMbtu. The continued outage at Freeport LNG and the first expansion of the storage surplus in several weeks weighed on prompt month prices.
While Freeport LNG did begin to receive some gas volumes this week, its intake has once again fallen to zero as maintenance continues. Flows peaked at 520 MMcf/d on Monday, indicating that one liquefaction train was receiving gas before falling and remaining offline for the rest of the week. This extended outage has weighed on the gas market, reducing total US feedgas demand, averaging 11.5 Bcf/d this week.
The storage surplus to the five-year average has shrunk over the past several weeks, but this trend reversed this week, according to the EIA’s weekly natural gas inventory report. Currently standing at 655 Bcf above the five-year average, this represents an increase of 33 Bcf from the prior report. While still lower than the peak seen four weeks ago of 669 Bcf, an increase in the surplus is a bearish development. This increase was likely driven by weak LNG feedgas volumes and unsupportive weather-driven demand.
AEGIS holds a neutral view on near-term summer prices given the substantial supply response seen thus far while maintaining a bearish outlook on Winter ‘24/’25. Swaps are recommended for hedging the summer months and costless collars for the winter months.
Natural Gas Factors
Price Trend. (Bearish, Priced In) Gas prices finished lower this week. Prices fell despite low production, swelling storage surplus, and a weak weather outlook into April and May. The May'24 NYMEX Henry hub lost 14c or 7.8% to finish at $1.61/MMbtu
S&D Balance. (Partly Bearish, Priced In)
Weather. (Bearish, Priced In) The Euro Ensemble forecast indicates a cooler shift for most parts of the U.S., with overall temperatures across the Lower 48 decreasing by an average of 5 degrees, though the West saw a slight increase in warmth. The latest models confirm this cooler trend, aligning early May temperatures closer to the 10-year average. Despite a warmer outlook for next week, temperatures are expected to moderate the week after. Heating degree days (HDDs) are set to return by the weekend, following a few cooling degree days (CDDs) next week, but both HDDs and CDDs will remain limited through early May.
Storage Level. (Bearish, Priced In) The storage level is a bearish priced-in factor due to the high levels of gas in inventories relative to the five-year average. According to the latest EIA weekly natural gas inventory report, the surplus to the five-year average, which had been narrowing, reversed this week, rising by 33 Bcf to 655 Bcf above the average. Although this is still below the peak of 669 Bcf seen four weeks ago, the increase in the surplus, likely caused by low LNG feedgas volumes and weak weather-driven demand, is seen as a bearish development for the market.
Dry Gas Production & Associated Gas Production. (Bullish & Bearish, Partly Priced In) These are the most critical drivers of gas prices outside of weather. A material increase in either would pressure prices lower and loosen the supply-demand balance. These are also longer-lasting factors that can weigh on prices for years. Production was on the rise heading into 2022 year-end, mirroring the late push observed in 2020, particularly in the Appalachia, Haynesville, and Permian. Producer discipline, takeaway capacity constraints in some basins, and gas prices will likely drive production growth moving forward. The recent weakening in Waha forward prices may be a market signal that associated gas production could grow and face takeaway capacity constraints in 2023. However, with gas prices falling sharply, the risk of a decline in production is a potentially large bullish surprise factor that the market has not priced in.
LNG. (Bullish, Priced In) As temperatures remain miland the maintenance season is almost over, LNG flows are near 12.5 Bcf/d. LNG feedgas demand has consistently exceeded 12 Bcf/d since the start of December 2021. As consumers avoid Russian fuel, demand for U.S. LNG is surging, reviving several long-stalled U.S. export projects. However, these projects will not be operational until at least late 2024. Sabine Pass's Train 6 and Calcasieu Pass have finished construction and started operations in 2022. There is going to be a lull in new feedgas demand until ExxonMobil's Golden Pass facility comes online in 1H-2025.
ExxonMobil has postponed the start of operations for its Golden Pass LNG Train 1 from August 2024 to the first half of 2025, with the facility likely to be mechanically complete by the end of 2024. Initial gas flows are expected around late December 2024 or early January 2025, and Train 1 is projected to have a capacity of 0.68 Bcf/d. Meanwhile, Plaquemines stage 1 is set to have a prolonged start period of about 24 months. It is still expected to come online in 4Q 2024.
Renewables. (Mostly Bearish, Partly Priced In) Renewables remain a perennial threat to gas prices and gas's share of the power stack. Renewable capacity additions in 2023 are expected to set a new record and are now the second-most prevalent source of electricity generation. Still, renewables have proven unreliable at times, which has exacerbated the global energy squeeze as gas usually serves as a flex-fuel when other sources underperform. We think this is priced in, but the effect at the summer peaks on gas generation has some bearish potential.
LNG Outages. (Bearish, Surprise) Feedgas at Freeport LNG is expected to reach 0.3 Bcf/d, signaling partial resumption with one train coming back online post-outage. Freeport LNG's Trains 1 and 2 remain shut until May for inspections and repairs; Freeport LNG resumed receiving gas volumes earlier this week, peaking at 520 MMcf/d on Monday, which suggests one liquefaction train was operational before intake dropped to zero again due to ongoing maintenance. This fluctuation and the train remaining offline for the rest of the week have contributed to a decrease in the overall U.S. feedgas demand, which averaged 11.5 Bcf/d this week, exerting downward pressure on the gas market.
Feed-gas levels are at their near max capacity, and if there's any unplanned maintenance event or an outage, it might act as a surprise bearish factor for natural gas prices.
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