Natural gas futures found fresh footing Monday for the first time in six sessions, supported by a cold shift in late November forecasts, while bears eyed next opportunities with supply still ample and another potential disruption at the Freeport LNG facility in Texas.
At A Glance:
- Prompt month ends five-session slide
- Production jumps near 106 Bcf/d
- NGI estimates 9 Bcf draw and 43 Bcf injection
The December Nymex natural gas futures contract jumped 16.4 cents day/day to settle at $3.197/MMBtu. January rose 11.6 cents to settle at $3.400.
NGI’s Spot Gas National Avg. catapulted 42.5 cents higher day/day to average $2.650, led by increases in the Rockies. But gains were widespread across regions, except for West Texas dealing with pipeline maintenance.
Early in the regular trading session on Monday, the prompt month jumped after weather models turned cold over the weekend. Analysts had warned that weather models calling for one of the warmest Novembers in decades were likely to revert colder.
Indeed, the pendulum swung colder. A major model added 3-4 heating degree days (HDD) over the weekend, then added another nine HDDs overnight and eight HDDs by midday Monday, NatGasWeather said. This shift equates to another 20 HDDs, or 30 Bcf of demand, for the five to 13-day forecast added since Friday, the firm said.
“It's not a surprise the data is trending colder, since as we mentioned last week there was little room for the pattern to be further warmer/bearish, and odds favored some demand would be added,” NatGasWeather said.
By noon, most of the juice had been squeezed from the weekend forecast revisions, and December futures had given back some of their gains. But then midday forecasts tacked on more demand, and futures rallied 10 cents without turning back into the afternoon close. NatGasWeather issued an extra report after its midday update to relay that another model was trending even colder than its counterpart, with colder weather in northern states expected this coming weekend into next week.
By Thanksgiving, overall demand would rise to seasonal levels, the firm said.
EBW Analytics Group analyst Eli Rubin also had anticipated cooler forecasts triggering a relief rally. This has set up a “cautiously bullish forecast for the last week of November” but the durability of “the coming chilly weather, however, remains in question into early next month.”
Supply/Demand Situation
Against this backdrop of supportive colder weather, bearish headwinds mounted on both the supply and demand fronts.
Natural gas production marched higher to new records over the weekend, hitting 105.8 Bcf on Friday, 105.7 Bcf on Saturday and 105.9 Bcf on Sunday, Wood Mackenzie estimated. That put the firm’s seven-day average of 105.5 Bcf/d sharply higher than the 30-day average of 103.7 Bcf/d.
But on the demand side, Freeport LNG stoked anxiety that exports could stumble a bit. Nominated flows on Freeport’s primary supply route, the Gulf South Pipeline system, dropped to 54% of design capacity on Thursday and remained reduced before recovering to near-average levels on Sunday, according to pipeline data from Wood Mackenzie.
The company reported the facility “experienced a trip of the Liquefaction Train 3” Thursday that led it to flare intermittently for more than eight hours.
Balancing out the net of these vying factors — colder weather, record output and an LNG disruption — has been complicated by the delay of last week’s government storage report. The U.S. Energy Information Administration (EIA) is scheduled to release storage prints for the weeks ended Nov. 3 and Nov. 10 on Thursday, after a planned systems upgrade last Thursday delayed the release of the Nov. 3 print.
In that week, much of the country got its first decent taste of winter, and the resulting demand could have been enough to flip gas to its first withdrawal of the season. NGI modeled a 9 Bcf withdrawal for the week ended Nov. 3. Estimates submitted to Reuters ranged from a withdrawal of 20 Bcf to an injection of 21 Bcf, with the median landing at a withdrawal of 7 Bcf. These estimates compare with a five-year average 36 Bcf injection and a 83 Bcf year-earlier build.
For the week ended Nov. 10, NGI is modeling a storage injection of 43 Bcf. That compares with a five-year average 20 Bcf injection and a year-earlier injection of 66 Bcf for the week.
One complicating factor in estimates for November is some facilities sticking to withdrawals even if the overall trend flips back to injection, according to Patrick Rau, NGI director of strategy and research.
“We’re into November and there are utilities who tend to want to burn gas from storage. In some cases, it may be mandated by their public utility commissions. They are burning gas or taking gas from storage that they injected earlier in the year when prices could have been lower,” Rau said.
From an accounting perspective, “it’s cheaper to burn the gas now versus the more expensive spot gas, all things being equal, especially if they think they’re well-supplied for the winter,” he said. “I think there’s an element of that going on, despite high production levels,” he said.
In addition, some nonsalt storage facilities could now be stuck in withdrawal mode if they had flipped from injections, according to Rau. This is unlike salt storage that can cycle back and forth.
Monday Cash Prices
Spot natural gas prices jumped Monday for their third consecutive daily session gain.
Prices across the West were higher, led by the Rockies regional average gaining $1.290 day/day to $3.620. Northwest Sumas led all hubs higher, up $2.745 to $4.710.
In California, Malin jumped $1.955 to $4.860, while PG&E Citygate rose $1.705 to $5.670. SoCal Citygate bucked the trend, falling for a fourth session, down 27.5 cents to $5.640. SoCal Citygate’s premium to nearby locations, fueled by inadequate capacity to handle all its nominated demand, has recently drawn the fire of buyers.
There were no signs of freeze-offs amid frigid temperatures from Montana down into Colorado, with production in the Rockies at 7.6 Bcf on Monday, not far off its all-time high around 7.7 Bcf. Instead, the West’s price strength is more likely a result of reduced flows out of its biggest supplier, the Permian Basin, with about 1 Bcf/d of capacity cuts from maintenance.
Kinder Morgan Inc.’s Gulf Coast Express (GCX) said it would conduct one week of inspections and maintenance on compressor stations along its pipeline that runs from the Permian Basin to hubs along the South Texas coast. In a notice to shippers, GCX indicated that on Tuesday and Wednesday (Nov. 14-15), flows would be reduced to 1.2 Bcf/d. The cuts would ease from Thursday to Friday (Nov. 16-17), with flows reduced to 1.35 Bcf/d, then from Saturday to Monday (Nov. 18-20), with flows reduced to 1.6 Bcf/d.
With an implied initial cut of 0.8 Bcf/d off GCX’s nominal capacity of 2 Bcf/d, Wood Mackenzie analyst Ricardo Falcon-Bautista said the “upcoming restrictions will likely have sizable physical impacts on natural gas flows” and “may add downside to an already weakening, volatile Waha cash price.”
Waha shed 27.0 cents to average 57.5 cents Monday. Transwestern, which briefly went negative last week, fell 46.0 cents to a cash price of 34.5 cents.
Falcon-Bautista pointed to possible additional support for Waha gas prices: the 0.5 Bcf/d expansion of the Whistler Pipeline.
Whistler, now with about 2.5 Bcf/d capacity, runs from the Permian’s Waha hub to the Agua Dulce hub in South Texas. If its new capacity is not already filled up, Permian gas could find its way to Aqua Dulce and support the Waha cash price, Falcon-Bautista said.
Elsewhere in East Texas, Gulf South Pipeline Co. has indicated that it would perform pipe maintenance on its Index 99 loop northeast of Houston Tuesday to Thursday (Nov. 14-16), which could reduce Texas receipts by up to 409 MMcf/d, with a complete shut-in at the Bland Lake-Kudo gathering system interconnect in San Augustine, TX, according to Wood Mackenzie.
