Natural gas forward prices retreated through the Aug. 10-16 period as long-range forecasts point to a cooler end to the month with an increase in tropical activity. Strong production levels outside of maintenance, lagging LNG demand and robust underground stocks also weighed on the market, sending September forward prices down an average 25.0 cents, according to NGI’s Forward Look.
Prices were mixed further out the curve, with some upside risk priced into the Northeast and Appalachia markets. On average, the winter 2023-2024 strip (November-March) fell an average 6.0 cents, and the summer 2024 strip (April-October) decreased an average of 2.0 cents.
West Coast markets continued to stand out from the crowd, recording sharp declines across the forward curve. The steep plunge was significant since it occurred during one of the hottest weeks of the summer.
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The National Weather Service (NWS) said Thursday one more day of oppressively hot temperatures was forecast for the interior Northwest and portions of the Northern Rockies/adjacent High Plains. Highs were forecast in the upper 90s to low 100s, near record levels for portions of the Northern Rockies. In addition, low relative humidity and gusty winds raised the risk of fires through Friday, particularly for portions of eastern Washington and northwestern Montana.
NWS forecasters said a Pacific system/cold front pushing southeast across the region overnight would bring an end to the more dangerous heat, though conditions would remain seasonally hot.
Prices at the SoCal Citygate, often the highest-priced location in the country, plunged $1.060 for September from Aug. 10-16 to reach $5.935, according to Forward Look. The winter 2023-2024 strip dropped 47.0 cents to $8.353, while summer 2024 slipped 6.0 cents to $3.370.
Prices in Northern California also plummeted through the period. PG&E Citygate September prices dropped 74.0 cents to $5.306, and winter 2023-2024 fell 26.0 cents to $7.417. The summer 2024 contract posted a modest 3.0-cent increase to average $4.910.
The hefty discounts extended into the Rockies as well. Northwest Rockies September tumbled 99.0 cents through the period to $3.562, while winter 2023-2024 dropped 43.0 cents to $6.595, Forward Look showed. Summer 2024 strip prices were down 12.0 cents to $3.410.
Similar changes were seen at Northwest Sumas. Notably, though, winter 2023-2024 strip prices at $9.094 were the second-highest in the country even after shedding 58.0 cents during the week.
Though cooler weather had a hand in the steep price declines at the front of the forward curve, other developments also were likely in play.
Over the past week, California regulators have appeared to soften their view of natural gas usage, at least in the near term. While the end goal remains to reduce reliance on fossil fuels, the California Public Utilities Commission (CPUC) could vote by the end of the month on a proposal to raise the maximum gas storage level at the Aliso Canyon storage facility.
CPUC last month recommended granting Sempra utility Southern California Gas Co. (SoCalGas) the ability to increase its maximum gas storage level to 68.6 Bcf from 41.16 Bcf at the Aliso facility. The staff responded to calls from SoCalGas and San Diego Gas & Electric Co., which argued that increased storage at Aliso would ultimately result in less volatility and more reasonable prices this winter.
Meanwhile, the California Energy Commission earlier this month voted to extend the deadline to shut down the three natural gas plants to the end of 2026. The Ormond Beach Generating Station, AES Alamitos and AES Huntington Beach, all in Southern California, would remain open to ensure ample power during emergencies and extreme weather conditions. The plan awaits final approval from the State Water Resources Control Board, which could vote this month.
The improved supply outlook would bode well for California and neighboring regions that experienced historic volatility and prices last winter.
Strong Supplies Unmatched
Elsewhere in the Lower 48, prices moved lower given little change in the fundamental backdrop in the market, with hefty supplies out-muscling the weather-driven demand stemming from heat from California to across Texas.
Production continued to hover above 100 Bcf/d for the most part, with dips ultimately proving to be temporary.
Underground storage has become more supportive in recent weeks, though, as prolonged heat across Texas has steadily chipped away at the storage surplus. The latest government inventory data continued this trend.
The Energy Information Administration (EIA) said stocks for the week ending Aug. 11 rose by 35 Bcf, a figure the market largely had projected. It trimmed the surplus to the five-year average by 6 Bcf week/week to 299 Bcf.
Ahead of Thursday’s EIA report, the average of 14 injection estimates submitted to Reuters had shown a 34 Bcf build, with predictions ranging from 29 Bcf to 39 Bcf. NGI had modeled a 36 Bcf injection.
The Midwest led with a build of 19 Bcf, while the East added 17 Bcf.
Notably, Pacific stocks rose by 7 Bcf, trimming the deficit to the five-year average to single digits with another 10 weeks to go in the injection season. Mountain inventories increased by 6 Bcf.
The South Central region, meanwhile, continued to withdraw to cope with strong demand for power generation. Salts took 12 Bcf out of inventories, while nonsalts pulled 3 Bcf.
Total Lower 48 working gas in underground storage stood at 3,065 Bcf as of Aug. 11, or 10.8% higher than the five-year, according to EIA.
Mobius Risk Group said the reference week in the latest EIA report was significantly cooler than the same week last year, off by 14 population-weighted cooling degree days. The week also experienced a “less jarring” year/year reduction in wind output, according to the firm.
These two factors, along with robust production, support the larger net injection compared with the 21 Bcf that was added in the same week last year.
Notably, though, salt storage posted the fourth consecutive double-digit weekly withdrawal. This compares with the same week last year, when salts withdrew 7 Bcf.
However, with weather models continuing to cool – and the seasonal peak of summer likely in the rearview mirror – stout storage surpluses could remain intact ahead of winter and send prices lower in the coming weeks.
There were only minor revisions in the latest weather data, with the period from Sunday (Aug. 20) to Aug. 25 forecast to be unusually hot. With cooler weather on the front and back ends of the long-range outlook, though, it was unclear whether there would be enough demand on the horizon to meaningfully change the near-term trajectory for prices.
Further out the curve, Henry Hub prices for the calendar year (CY) 2024 averaged $3.580. They averaged $4.004 for CY 2025 and $4.030 for CY 2026.
Mobius said long-dated natural gas remained a “challenging” risk management prospect for both producers and consumers.
For the producer, the ability to lock-in pricing above levels that support drilling economics is enticing, according to Mobius. At the same time, looming liquefied natural gas export expansions suggest the promise of “explosive upside,” it said. From the consumer’s perspective, the firm said it may be “hard to stomach” adding protection at $4.00 or more when only two years out of the past 10 have seen a realized price over that level.
“Of course, one of those years is very recent, and if global LNG export capacity is cut for any meaningful duration, the European continent could once again provide a pull on domestic markets,” Mobius senior analyst Zane Curry said. “On this final point, both producers and consumers would be wise to focus attention more on the shape of the curve rather than outright price levels.”
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