Stubbornly high production maintained its grip on natural gas forward curves during the May 18-24 period, with June prices averaging 20.0 cents lower, according to NGI’s Forward Look.
With weather-driven demand at seasonal lows and storage inventories remaining at a surplus to historical norms, forward contracts dropped 16.0 cents on average for the balance of summer (June-October). The winter months (November-March) averaged 12.0 cents lower through the period, while losses of 10.0 cents or less were seen for the summer 2024 strip (April-October).
Key outstanding questions suggest weakness may endure during the first half of summer, according to EBW Analytics Group. The firm said weather-driven demand may not firm up until July. Current outlooks from forecaster DTN showed cooling degree days (CDD) tracking only seven CDD above normal for June. By July, however, DTN’s most likely forecast called for 385 CDDs – 31 above normal – as warming potential eventually awakens cooling demand.
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LNG demand, while strong, also is off recent highs. The Cameron liquefied natural gas export terminal has returned from scheduled maintenance, but Corpus Christi and Sabine Pass continue to take in lower feed gas volumes amid turnarounds. NGI data showed feed gas deliveries to U.S. export terminals sitting at around 12.8 Dth/d on Thursday, up from sub-12 Dth/d levels seen last week but shy of highs of more than 14 Dth/d earlier this year.
More importantly, according to EBW, the global LNG picture could begin to clarify over the next 30-45 days. Bears continue to harp on elevated European storage figures as a risk for economic shut-ins during the fall. In EBW’s view, however, lower prices are likely to catalyze higher natural gas demand in both Europe and price-sensitive Asian countries to help absorb supplies.
Further, the market could turn to floating LNG supplies to help offset winter fuel adequacy risks in Europe while continuing to absorb export volumes from the United States. As the international demand picture begins to clarify, the weight from bearish risks on Nymex futures may begin to lift.
“The key barometer, however, will remain on the supply side of the equation,” EBW senior energy analyst Eli Rubin said.
Baker Hughes Co. rig data emboldened bulls earlier this month with a decline of 16 natural gas rigs during the week ending May 16. Prices swiftly rallied as the gas market took the rig decrease as a sure sign that a supply response to the low price environment was coming.
Instead, last week’s Baker Hughes data showed the number of natural gas rigs holding steady week/week, though oil-directed rigs declined. At the same time, recent production figures show output holding stubbornly around the 100 Bcf/d mark in spite of maintenance events taking place across the country.
However, the latest Enverus rig data, released Thursday, showed the U.S. oil and natural gas rig count falling by 13 rigs from the previous week’s peak, down to 767 for the period ending May 24. The Enverus count, which is included in the Baker Hughes weekly tally, was down 5%, or 42 rigs, in the last month and down 7% year/year.
The only major play to not see a decline in rigs was the Appalachian Basin, which added one for a total of 54, according to Enverus. The Permian Basin had the largest decline of six rigs to 335, while the Anadarko Basin fell by three to 60. The Gulf Coast dropped two rigs to 86. The Denver-Julesburg and Williston basins each dropped one rig to 17 and 37, respectivley.
“Long-lead indicators of dry gas production are suggestive of tapering momentum into the back half of the year,” EBW’s Rubin said. “Still, it takes time to turn long-term natural gas production trends. Instead, as production bouncing to three-week highs on Monday indicate, dry gas supply could still rebound higher into the summer as the limiting factor of pipeline constraints ease. The market remains exquisitely sensitive to production – and any uptick could reinstill bearish momentum for Nymex futures.”
Aegis Hedging Solutions noted that prices along the Waha forward curve have improved off earlier lows, even as estimated Permian dry gas output has eclipsed 17 Bcf/d.
Forward Look data showed Waha bucking the downtrend as June prices climbed 14.0 cents from May 18-24 to reach $1.642. The balance of summer averaged only 3.0 cents higher at $1.670, while the winter 2023-2024 strip held steady week/week at $2.920.
Improvement in forward strips beyond this summer coincides with additional eastbound egress capacity. However, Permian gas growth is expected to fill new capacity rather quickly, leading to continued downward pressure on Waha. Indeed, the summer 2024 strip fell 3.0 cents through the period to average $2.390.
The Waha curve, through the end of 2024, will continue to be at risk, according to Aegis. The greenfield 2.5 Bcf/d Matterhorn Pipeline is expected to come online in December 2024, providing relief.
“This has us less worried about Waha in 2025, albeit the pace of production will dictate how long that relief lasts,” Aegis analysts said. “The most acute risk for Waha prices is this summer before Whistler’s expansion is set to come online. A negative flat price for Waha is possible as egress is tested. Any combination of low demand and or pipeline maintenance (planned or unplanned) could push Waha negative.”
Storage Update
Other aspects of the supply side of the equation also remain mostly bearish for the time being.
The Energy Information Administration (EIA) on Thursday said inventories increased by 96 Bcf for the week ending May 19, on par with the five-year average and only 8 Bcf higher than the year-ago build. Notably, the injection once again fell short of the triple-digit mark many analysts had projected.
That said, Enelyst managing director Het Shah said the 96 Bcf figure doesn’t necessarily confirm the tighter balances reflected in last week’s EIA report. Instead, he views the latest injection as being tied to lower wind generation that increased the call on natural gas for power generation.
The East led with a 31 Bcf increase in storage, followed by the Midwest with a 26 Bcf build. The South Central added a net 19 Bcf to stocks, which included a 14 Bcf increase in nonsalt facilities and a 4 Bcf increase in salts.
The Pacific region, though still lagging historical levels, added a stout 12 Bcf to inventories. Mountain stocks rose by 8 Bcf.
Total working gas in storage climbed to 2,336 Bcf, which is 529 Bcf above year-earlier levels and 340 Bcf above the five-year average, according to EIA.
Mobius Risk Group noted that the next three reporting periods are all forecast to be milder than the comparative weeks from last year. To be sure, expectations for the next EIA storage report are for an injection near 110 Bcf.
Without a material change in underlying supply and demand, the market is likely to face a string of surplus expansions through the comparable week last year when Freeport LNG shuttered following an explosion, according to the firm. It noted that weather demand also stands to come more into play around that time, and depending on how it shakes out, this could be a pivotal point for the market.
Currently, the European weather model has temperatures in the southern tier of the United States warming up materially versus what is predicted by the American Global Forecast System model. “This, coupled with a likely path to substantial year/year increases in LNG feed gas demand, are a signal market bulls are looking for,” Mobius’ Zane Curry, director of research, said.
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