Gas prices finish the week slighlty lower despite ample intraweek volatility.
Prompt-month natural gas finished the week down 3c to $2.88 Friday to Friday. The small weekly decline came amid ample intraweek volatility, where July futures reached as high as $3.15/MMBbtu.
Natural gas prices have been benefiting from above-average June temperatures. If the current forecast holds for the rest of the month, June will be the hottest June on record regarding cooling degree days for the Lower 48. Higher cooling demand causes gas consumption for power to be greater than expected.
One of the factors that weighed on prices this year was the ample amount of natural gas in inventory. The gas surplus to the five-year average currently sits at 573 Bcf as of June 7. The EIA reported a 74 Bcf build in underground storage, coming in near the average analyst estimate of 76 Bcf. The AEGIS estimate missed the actual by 2 Bcf at 72 Bcf. July gas prices pared gains on Thursday morning as the market sold on the news of the 74 Bcf injection.
Looking more regional, Equitrans Midstream Corp. announced that the Mountain Valley Pipeline (MVP) has begun service. MVP is a 2 Bcf/d greenfield pipeline that will move gas from southwest Appalachia to demand centers in the Southeast. “MVP is now available for interruptible or short-term transportation service until long-term firm capacity obligations commence on July 1, “according to Equitrans. A previous analysis done here by AEGIS shows that MVP will be unable to flow the full 2 Bcf/d for some time as there are downstream constraints of the Transco mainline, where MVP terminates. Transco plans to add enhancements and additions to the mainline over the next few years to allow MVP to reach its full potential. Due to the slow ramp-up of this new takeaway capacity, AEGIS suggests the impact on local basis will be minimal.
Natural Gas Factors
Price Trend. (Bearish, Priced In) Gas prices posted a second straight week gain. Prices rallied amid recovering production, modestly shrinking storage surplus, and a bullish weather outlook into late June. The July '24 NYMEX Henry hub gained 33.1c or 12.8% to finish at $2.918/MMbtu
S&D Balance. (Partly Bearish, Priced In)
Summer Weather. (Bullish, Surprise) 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. The latest European Ensemble model shifted warmer, with nearly every region showing increased temperatures. The overall gain for the Lower 48 was +3.7 degrees, mostly within the next 10 days. Despite this, the pattern remains consistent: cooling next week, followed by above-normal temperatures in mid/late June. The forecast predicts warm temperatures in late June, with both daytime and nighttime temps rising. The peak Cooling Degree Days (CDDs) will occur in the 11-15 day period. The week ending 6/21 is expected to see temperatures increase by over +4 degrees.
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.
Summer Weather. (Bullish, Surprise) If weather comes in materially warmer than the ten-year average, then the storage surplus to the five-year average may shrink at a faster rate. Hotter weather should lead to higher power sector gas demand and with less coal-to-gas switching availablity, gas has held a higher share of the power mix.
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