Blazing Hot Southern California Posts Huge Price Spikes Along Natural Gas Forward Curve
With dangerous heat leaving California electric grid operators struggling to meet heightened demand, natural gas forward prices in the southern part of the state rallied sharply from July 20-26, according to NGI’s Forward Look.
Daytime temperatures have lingered at or above the century mark for most of July in parts of California, driving up cooling loads and prompting the state’s independent system operator (ISO) to warn of a potential supply shortfall. The California ISO said in an Energy Emergency Alert (EEA) Watch on Wednesday some resources went offline amid the excessive heat in the interior. In addition, transmission congestion restricted movement of power to some areas.
The EEA Watch is called when the grid operator’s day-ahead analysis shows that all resources are committed or forecast to be in use, and energy deficiencies are expected at the specified time. The declaration initiates demand response programs that may alleviate high loads during the evening when solar production is rolling off the system. It also encourages market participants to bid energy into the market.
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“The ISO is seeing some supply uncertainty this evening, because of heat potentially pushing up demand, and high electricity demand across the western U.S.,” the grid operator said.
Wednesday was the second day in a row the ISO issued an EEA.
With triple-digit temperatures remaining in the forecast and unplanned maintenance at Line 225 that is expected to cut receipts at Wheeler Ridge by 650 MMcf/d through Aug. 11, natural gas forward prices jumped sharply, particularly at the front of the curve.
At the SoCal Citygate, August forward prices shot up $2.990 from July 20-26 to reach $9.506/MMBtu, Forward Look data showed. The balance of summer (August-October) climbed $1.340 to average $7.160. Smaller price increases were seen further out the curve, with the winter 2023-2024 (November-March) strip up 37.0 cents to $8.332 and the summer 2024 (April-October) strip up 16.0 cents to $5.180.
The SoCal Border Avg. also rallied but trailed the citygate by a wide margin, according to Forward Look. SoCal Border Avg. August forward prices tacked on 53.0 cents through the period to reach $5.424, while the balance of summer rose 31.0 cents to $4.660. Winter 2023-2024 averaged 36.0 cents higher at $6.627, and the summer 2024 averaged 16.0 cents higher at $4.090.
For comparison, prices in Northern California barely budged. PG&E Citygate August fell 5.0 cents to $5.374, while the balance of summer edged up 1.0 cent to $5.200. Notably, though, the winter 2023-2024 strip jumped 39.0 cents to $6.741. Summer 2024 prices tacked on 6.0 cents to $4.630.
AccuWeather said there may be some relief on the horizon from the sweltering conditions. The long-awaited return of the annual North American monsoon already has put an end to the record-long streak of heat in Phoenix, with more rain chances this weekend and into next week.
Thunderstorms were expected to be isolated for the remainder of the week and into the weekend. After that, the monsoon moisture should intensify, which would result in more widespread showers, and a relocation of the persistent heat dome farther east, according to AccuWeather.
“Monsoon moisture will shift westward for Sunday into Monday into Southern California, underneath the persistent heat dome,” AccuWeather senior meteorologist Heather Zehr said. “This will bring rain chances into at least the deserts of California, and perhaps the mountains to the north and east of Los Angeles and San Diego.”
The storms could then spread north into the Sierra Nevada mountains of California and Nevada from Monday into Tuesday, according to Zehr. Outside of Arizona, California and Nevada, more of the Intermountain West from New Mexico to Idaho should experience an uptick in daily thunderstorm activity through next week along with a drop in temperature.
Weak Prices Elsewhere
The steep price hikes in California compared with mostly softer forward curves in other regions of the Lower 48. Even with scorching temperatures in Texas and the South, the front of the curve sold off amid a robust supply picture.
For example, Henry Hub August prices stood Wednesday at $2.657 after falling 10.0 cents from July 20-26, according to Forward Look. The balance of summer slipped 5.0 cents to $2.720. Beyond the summer, however, modest price increases were seen for the winter 2023-2024 strip, which averaged $3.601, and the summer 2024 strip, which averaged $3.320.
At the Houston Ship Channel, August lost 12.0 cents to reach $2.434, and the balance of summer dropped 8.0 cents to average $2.450. The winter 2023-2024 was up 5.0 cents to $3.556, while summer 2024 picked up 4.0 cents to average $3.060.
The weakness seen for the remainder of summer comes as both production and storage levels have surprised to the upside.
Bloomberg data showed Lower 48 dry gas production sitting close to 101 Bcf/d on Thursday, up from recent lows near 99 Bcf/d that were related to pipeline maintenance events taking place across the country. That’s been the situation all summer, with any declines in output eventually recovering back to near-record highs once maintenance concludes.
That said, production appears increasingly likely to soften into the fall, according to EBW Analytics Group. The firm noted that weakening regional demand moving into early and mid-September portends lower basis price differentials in the Marcellus Shale. This provides a more opportune time for producers to conduct field-level maintenance, slow production activities or accrue drilled but uncompleted wells ahead of the winter.
“We continue to note the steep 41-cent spread between the October and November contracts available to producers with flexibility to shift production profiles,” EBW senior energy analyst Eli Rubin said on Wednesday.
With the notable exception of the Whistler Pipeline expansion anticipated to unlock up to 0.5 Bcf/d of Permian Basin supplies, lower production across the Haynesville Shale and Appalachia Basin could lead national supply to dip, according to Rubin.
Recent drilling rig data support this theory. The number of rigs operating in the Haynesville stood at 44 as of July 21, off one week/week and down from 68 a year ago, according to Baker Hughes Co. The Marcellus count was flat week/week and down only three rigs from a year ago.
Storage Plump Too
Outside of production, underground supplies of gas also have weighed on prices as inventories have maintained a stout surplus over historical levels.
On Thursday, the Energy Information Administration’s (EIA) latest stock report surprised to the upside as 16 Bcf was injected into storage for the week ending July 21. This lifted working gas in storage to 2,987 Bcf, which is 573 Bcf above year-earlier levels and 345 Bcf above the five-year average.
Though the build slightly surpassed expectations by a couple of Bcf – NGI modeled an increase of 14 Bcf – the 16 Bcf figure was close to last year’s 18 Bcf build. However, it fell well short of the 31 Bcf five-year average.
The Midwest led with a 16 Bcf injection for the period, followed by a 9 Bcf increase in the East, EIA said. Mountain stocks increased by 3 Bcf, while the Pacific showed no net change on the week. The South Central, meanwhile, reported an 11 Bcf withdrawal that solely was from salt facilities.
Mobius Risk Group said the 11 Bcf draw in the South Central region was right in line with last year’s pull in the same week. After nine straight weeks of increases in the year/year salt storage surplus, this should be a welcome sign for market bulls, according to the firm. At the same time, the latest data should provide a warning for market bears who are still banking on a blowout this fall.
Data for the next storage report were tracking toward another double-digit salt storage withdrawal in the South Central region, according to Mobius. Notably, this would compare with the prior year comp of a modest 2 Bcf withdrawal.
EBW said the South Central would need to tighten to offer prices a chance at more sustained upside into late summer and early fall. In the immediate term, sizzling temperatures across the country could increase the call on salt storage inventories. However, EBW noted that soft spot prices were not indicative of enormous opportunities for salt storage operators.
Instead, it is possible that underperforming LNG exports that utilize salt storage for operational needs may be contributing to pushing incremental supply back on the U.S. market on the margins. NGI data showed feed gas deliveries to U.S. liquefied natural gas export terminals continuing to sit back of earlier highs. On Thursday, feed gas volumes were seen slightly above 12 Dth/d from highs above 13 Dth/d at the start of the week and off from the 14 Dth/d-plus levels seen earlier this year.
“A medium- to longer-term price increase may be dependent on regional production growth subsiding and LNG exports picking up strength,” Rubin said.
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