Natural Gas Prices Post Third Weekly Gain on Tight Supply-Demand Balance
The October NYMEX contract advanced 14c to settle at $2.44/MMBtu in the third consecutive week of higher settlement prices. The forward curve also increased, with Winter ‘24/’25 climbing 17c to finish at $3.16/MMBtu and Summer ’25 rising 10c to $3.12/MMBtu. Prices have been supported by a tight supply-demand balance, leading to a continuous shrinkage of the storage surplus.
According to our calculations, the weather-adjusted supply-demand balance is about 4 Bcf/d undersupplied, and it has been for the past few weeks. This is the most undersupplied it has been in over a year, contributing to the rapid shrinking of the storage surplus to the five-year average. By adjusting for the effect of weather, the model can show if storage levels would converge or diverge from the five-year average if temperatures were in line with the 10-year average. For the past several months, the supply-demand balance has skewed toward undersupply, given the decrease in gas supply this year, but has modulated between slight oversupply and about 2 Bcf/d undersupplied. The past several weeks represent the tightest conditions seen thus far.
According to S&P data, production levels are off the highs seen in late July and early August of about 103 Bcf/d, with current levels closer to 101 Bcf/d. This has mainly been driven by swings in Appalachian production. As we approach winter and higher demand months, Appalachian production may rise, as seen in previous years, which could lead to the supply-demand balance moving back towards neutral or less undersupplied levels. If production remains lower, storage may continue moving toward the five-year average and supporting prices.
AEGIS maintains a bearish outlook for Winter ‘'24/’25, a neutral outlook for Summer ’25, and a more positive view on prices into the latter half of the year and beyond. Swaps may be preferable in the summer months, while the winter has higher levels of call skew, which can make a costless collar more attractive.
Natural Gas Factors
Price Trend. (Bearish, Priced In) Gas prices have remained under pressure for several weeks, trading near $2/MMBtu after falling from $3/MMBtu in early summer. Prompt month gas posted a second consecutive weekly gain.
S&D Balance. (Mostly Bullish, Priced In)
Summer Weather. (Bullish, Priced In) Assuming normal weather, storage levels are expected to start winter elevated to the five-year average, but if weather comes in materially hotter than normal this summer then storage levels could end the season lower than currently expected. As summer has progressed, June came in as the hottest on record while July was more subdued but still slightly above the ten-year average. We believe this factor has become more priced in now. Today's European Ensemble showed limited changes, with the West trending warmer while the Lower 48 pattern remains stable, expecting steady temperatures over the next two weeks.
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 98 Bcf to 581 Bcf above the average. Although this is still below the peak of 669 Bcf seen last month, 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. (Bearish, Surprise) 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. Since the start of 2024, gas production has fallen sharply, driven by substantial curtailments and seasonal declines in Appalachia. Given low gas prices, producers may continue to curtail gas production until economics improve. A material drop in production could improve storage balances, but if prices begin to improve, there is a large amount of supply that can be brought back to market, which would be a bearish risk. With some evidence that production is now returning to the market, the dry gas curtailment bubble has been shifted to the bearish quadrant. A large amount of production was likely taken offline this year, which is now waiting to come back. Some operators may also have been drilling and completing wells during this time, which are ready to flow gas if economics have improved enough.
Associated Gas Production.(Bearish, Priced In)With oil prices remaining high and additional egress capacity coming to the Permian in the form of the Matterhorn pipeline, associated gas production may continue to grow in 2024. The Matterhorn pipe will send an additional 2.5 Bcf/d to the Gulf Coast, posing a bearish risk to Henry Hub and regional basis prices such as Houston Ship Channel.
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.
Above Average Hurricane Season. (Bearish, Surprise)NOAA is anticipating a record hurricane season this year, given extremely warm ocean temperatures and reduced wind shear from El Nino, which is expected to transition into La Nina. In the past, hurricanes had a bullish impact on gas prices from reduced Gulf of Mexico supply. However, with only ~2 Bcf/d of US production coming from the gulf and a significant amount of LNG exports and power demand situated in the region, hurricanes are now a bearish risk.
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