With the market awash in supply and staring at bearish forecast maps stretching deep into November, regional natural gas forwards sold off sharply across the winter strip during the Nov. 2-7 trading period, NGI’s Forward Look data show.
Henry Hub fixed prices saw deep discounts week/week, with December dropping 35.5 cents to $3.144/MMBtu. January, February and March at the benchmark each saw fixed price discounts of around 7% for the period.
Basis shifts week/week showed steeper declines at elevated New England hubs amid easing winter risks, particularly at the front of the curve. Iroquois Zone 2 December basis tumbled $1.189 to finish at plus-$2.854.
More impressive cold for the Lower 48 might not materialize until late November at the earliest, which could mean “bearish weather headwinds” for the natural gas market until then, NatGasWeather said Wednesday.
Midday weather data was slightly warmer trending, and forecasts continued to advertise widespread above-normal conditions for the Lower 48 between next Tuesday and Nov. 20, according to the firm.
“Long-range weather maps maintain a mild setup over much of the U.S. for the 16- to 20-day period,” NatGasWeather said. “...Some of the weather data has been teasing colder patterns showing up around Nov. 22-23 but hasn’t been consistent with it.” Thus, it would “require more evidence if the natural gas markets are to believe it.”
Basis Diffs Widen In Texas
With forecasts giving bulls little encouragement, and with LNG export demand potentially a lone fundamental bright spot heading into the early stretch of the heating season, basis differentials came under downward pressure throughout much of the Lower 48 to varying extents.
In South Texas, Agua Dulce basis shed 2.5 cents for December to end at a 35.0-cent discount to Henry Hub. January and February basis swings at the location also trended negative week/week but finished around 35 cents ahead of the Louisiana benchmark.
The week/week decline in basis prices comes with the peak summer season in the rearview mirror for Mexico, a key outlet for Texas natural gas supplies. After topping 7 Bcf/d this summer, pipeline exports to Mexico are expected to average only around 6.24 Bcf/d for the remainder of the year.
With minimal domestic production, Mexico relies heavily on U.S. gas supplies to meet its demand. Mexico's dry natural gas production averaged 2.54 Bcf/d this summer and fell to 2.13 Bcf/d in October. It is projected to decline further, to only 2.01 Bcf/d by summer 2025.
Basis price dynamics were similar at Houston Ship Channel and Katy in East Texas.
Meanwhile, over in West Texas, basis shifts pointed to a glut of supply flowing out of the Permian Basin at this point in the season, weighing on prices at producing area hubs.
Waha basis conceded ground across the strip; however, the hub remained in positive basis territory for January and February, trading at plus-11.5 cents and plus-12.5 cents, respectively.
Waha prices were a mixed bag in the 2022/23 winter, Daily GPI historical data show. At times, regional sellers enjoyed strong prices that coincided with premiums downstream at West Coast hubs like SoCal Citygate.
However, price blowouts and supply constraints at SoCal Citygate from late November through December 2022 coincided with occasional stretches of negatively priced day-ahead deals in oil-focused West Texas, suggesting severe congestion in connecting the region’s associated natural gas supply to where it was demanded.
West Coast Wobbles
California hubs continued to see large basis swings during the Nov. 2-7 period as traders attempted to find fair value for winter prices following extreme blowouts last winter.
SoCal Citygate January basis plunged 52.9 cents for the period to end at plus-$5.645. SoCal Border Avg. exited the period at plus-$4.453 for January, a 33.0-cent swing lower.
Daily market conditions at SoCal Citygate proved something of a contradiction during the Nov. 2-7 period, as day-ahead prices traded at elevated levels despite supply exceeding sendout on the Southern California Gas (SoCalGas) system, according to the operator’s electronic bulletin board. Excess supplies appeared to go toward daily net injections of around 400,000 Dth/d or more, SoCalGas data show.
The situation frustrated buyers at SoCal Citygate, a location known for its supply constraints, amid significantly cheaper day-ahead prices at the nearby hubs comprising the SoCal Border Avg.
Still, even as near-term conditions suggested a supply cushion in Southern California, and as U.S. Energy Information Administration data has shown Pacific region stockpiles recovering to above-average levels, to some extent the western Lower 48 natural gas market has been riding its luck.
That’s according to a recent blog post from RBN Energy LLC analyst Sheetal Nasta, who pointed out the “dire straits” the U.S. West Coast found itself in exiting the 2022/23 winter.
Harsh winter conditions regionally had left stockpiles at historic lows, “and it seemed like the region would be hard-pressed to refill storage to a reasonable given limited and constrained pipeline options to flow incremental gas west,” Nasta said. “Instead, a combination of mild weather and operational changes eased demand and pipeline constraints, and Pacific region storage staged a remarkable comeback this summer.”
Regional injections totaled 210 Bcf season-to-date as of early October, Nasta estimated, close to twice the rate of injections for the year-earlier period.
The California Public Utilities Commission (CPUC) decision in late summer to ease regulatory restrictions on the Aliso Canyon storage facility in Southern California also played a role in helping to alleviate the tight conditions out West, according to Nasta.
Ultimately, “it took a combination of mercurial factors – including mild weather, strong hydropower, favorable operation and pricing dynamics, and regulatory intervention – to improve the supply picture in the region,” Nasta said.
The region “clearly remains vulnerable to dislocations, and we’re likely to see some price blowouts this winter during peak demand days, albeit perhaps not to the extent of last winter,” Nasta added. “Moreover, long term, without additional capacity there’s always the risk that the next time West Coast storage gets depleted, it may not be so lucky.”
Futures Weighed Down By Oversupply
As reflected in regional forward price action, Nymex futures sold off heavily during the Nov. 2-7 trading period. Soaring production figures, a healthy storage buffer and widespread warmer-than-normal temperatures in forecasts resulted in double-digit declines for the December contract on both Monday and Tuesday.
The front month on Wednesday shed another 3.4 cents to settle at $3.106.
Looking at underlying fundamentals, domestic production clocked in at 103.9 Bcf/d for Wednesday in the latest estimates from Wood Mackenzie. That was close to the recent seven-day average of 104.4 Bcf/d and notably above the 30-day average of 103.2 Bcf/d.
Recent futures selling reflected production readings reaching “fresh all-time highs” just as November forecasts lowered weather-driven demand expectations, EBW Analytics Group analyst Eli Rubin said in a recent note.
A normal weather scenario at recent Nymex prices would see the market exit March with storage near 1,675 Bcf, a level “hardly indicative of massive oversupply,” according to the analyst.
An El Nino pattern this winter alongside rising production volumes that threaten “tremendous oversupply for next spring and early summer” pose “significant downside risks” for prices moving forward, Rubin said.
“It is unclear how the market will price these risks in November 2023, however, with the full winter withdrawal season still ahead,” the analyst said. “In our view, strong technical support near $3.07 may offer a short-term respite from selling pressures.”
