Widespread gains for the scorching West the notable exception, regional natural gas forwards generally skidded lower during the July 27-Aug. 3 trading period, NGI’s Forward Look data show.
For western U.S. hubs, enduring summer heat and an ongoing regional storage deficit put upward pressure on the late-injection-season contract months week/week. SoCal Citygate fixed prices jumped 78.4 cents week/week for October delivery to end at $6.282/MMBtu.
Elsewhere in the region, Malin October fixed prices added 38.9 cents to reach $3.579, Forward Look data show.
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The back half of the 15-day forecast as of Thursday showed “very warm to hot” temperatures blanketing the western and southern portions of the Lower 48, with the hottest conditions stretching from California to Texas, NatGasWeather told clients. This would include highs ranging from the 90s to the 110s, according to the firm.
This comes as the impact of recent summer temperatures resulted in a net withdrawal from storage of 2 Bcf for the Pacific region during the week ending July 28, U.S. Energy Information Administration (EIA) data show.
EIA Pacific region stockpiles stood at 230 Bcf as of July 28, lagging the prior five-year average by 13.5%. That stands in stark contrast to the Lower 48 as a whole, which exited the period at a 322 Bcf (plus-12.0%) surplus to the five-year, EIA data show.
Discounts Elsewhere
Consistent with the broader looseness implied by a still-hefty Lower 48 storage surplus as the end of summer approaches, September fixed price forwards at benchmark Henry Hub shed double-digits week/week, dropping 22.2 cents to finish at $2.478. That set the stage for front-month discounts of around a dime to a quarter for numerous Lower 48 hubs.
As forwards traders continued to price in the market’s seemingly comfortable storage buffer, they heavily discounted winter premiums at traditionally constrained demand hubs along the East Coast during the period.
January basis at Transco Zone 5 dropped $1.074 week/week, albeit still finishing at a substantial $3.081 premium to Henry. Algonquin Citygate January basis finished at plus $12.308, a 65.4-cent swing lower.
The East Coast winter discounts during the July 27-Aug. 3 period occurred as recent forecasts had generally shown far less heat for the Northeast compared to western and southern parts of the country. This, coupled with Henry Hub discounts and a 12.8% storage surplus for the EIA East as of July 28, seemingly helped to incrementally ease winter supply adequacy fears week/week.
‘Infirm Underlying Fundamentals’
Nymex futures posted multiple negative sessions during the July 27-Aug. 3 trading period, including a 17.3-cent loss for the July contract in its final day of trading. Coming off a 7.4-cent sell-off on Tuesday and an 8.3-cent slide on Wednesday, the September contract recovered some of its recent losses on Thursday, picking up 8.8 cents to settle at $2.565.
A supportive surplus-trimming storage print and some hotter-trending weather model runs may have helped bulls to regain some ground Thursday.
The American model as of midday Thursday had trended hotter by 6-7 cooling degree days over the prior 24 hours, advertising a pattern for mid-August that would be “plenty hot enough” to satisfy the natural gas markets, NatGasWeather said.
However, the hotter mid-August pattern was at risk of “trending cooler in time, as the data has done in most instances” throughout the summer, the firm said.
Setting aside the scorching temperatures in Texas, moderating summer heat over other portions of the country was “exposing infirm underlying fundamentals,” EBW Analytics Group analyst told clients in a recent note.
This fundamental weakness, driven in part by “elevated production and soft LNG” demand, could see prices continue to probe lower, according to the analyst.
“Although a projected narrowing in the storage surplus versus the five-year average may provide fundamental cover, the combination of enduring surpluses…and near-record production may postpone any near-term realization of upside for Nymex futures,” Rubin said.
Production Weakness By Fall?
Signs of a production retreat could start to show up heading into early fall, according to Rubin, who cited “visibly emerging” weakness in the Haynesville Shale. Activity has also been dropping for the Eagle Ford Shale and in the Midcontinent, the analyst said.
“Still, the 0.5 Bcf/d Whistler pipeline expansion remains on track for a September in-service date and could unleash a bottlenecked Permian,” Rubin said. “In our view, however, seasonal swings in Appalachian production…could help shift the narrative heading into early winter.”
The latest Enverus rig data showed a double-digit increase in the U.S. count for the week ending Aug. 2 when compared to the peak total for the week-earlier period. The latest weekly count was down 16% year/year but was roughly in line with the prior month, according to the firm.
“In the last week, the Permian added four rigs for a total of 313,” Enverus analysts said. “The Denver Julesburg Basin rose by two rigs to 18, and the Anadarko Basin added one rig to reach 51. Appalachia and the Gulf Coast lost one rig each for totals of 46 and 80, respectively. The Williston Basin dropped two rigs to 35.”
Recent East Daley Analytics estimates showed Northeast gross production averaging slightly more than 35 Bcf/d for the first half of 2023.
“After recovering from the strong winter weather at the beginning of the year, basin production has remained relatively flat with a small increase,” the East Daley analysts said. “The rig count in the region has been on average 49 for the past five months, and the pipeline sample, as expected, shows the same trend as gross production.”
Eastern Gas South September basis added 6.7 cents for the July 27-Aug. 3 trading period but remained at a $1.474 discount to the national benchmark, Forward Look data show.
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