Strong power burns and rising export demand launched spot gas prices sharply higher for the Oct. 19-23 period. Fueled by gains of more than 50.0 cents across much of the United States, but countered by steep losses in California and Appalachia, NGI’s Weekly Spot Gas National Avg. ultimately rose 42.5 cents to $2.405.
Benchmark Henry Hub picked up 53.5 cents week/week as feed gas demand from U.S. liquefied natural gas terminals soared to fresh highs after restrictions in waterways near the Sabine Pass and Cameron LNG terminals were lifted. By Wednesday, deliveries reached more than 8 Bcf, a level that was holding steady on Friday.
Power burns also remained strong despite the higher prices. Although much of the country is enjoying the cooler fall temperatures, cities across Texas and Louisiana continued to see daytime highs near 90 degrees.
Houston Ship Channel prices climbed 35.0 cents week/week to average 2.860. Steeper increases were seen in other parts of Texas.
Over in the Midwest, a wave of cooler air that moved into the region this week boosted gas demand. Chicago Citygate jumped 74.0 cents week to week to average $2.760.
Similarly sharp rises were seen in the Midcontinent and throughout the Southeast.
A different picture emerged in Appalachia, where the late-week blast of chilly air was not enough to keep prices from registering week/week declines. Columbia Gas was down 32.0 cents to $1.420. Transco Zone 6 NY in the Northeast posted a 20.5 cent drop to $1.100.
$3 Gas Not To Last?
In a historic week, natural gas futures crested the $3.00 mark for the first time in nearly two years as steadily rising export demand and lower production tightened up supply/demand balances. The rally was not to last, however, as Mother Nature threw cold water on the momentum.
The November Nymex futures contract finished Friday’s session at $2.971, down 3.6 cents from Thursday’s close but still a considerable 17.6 cents higher than Monday’s close.
The move lower occurred as the latest weather models solidified a warmer outlook for early November. Bespoke Weather Services said the models have moved toward strong upper-level ridging anchored over the Midwest, suggesting that risks to the current forecast still are to the warmer side after the first couple of days of November. There also is the possibility of a “strongly warm, very low demand pattern” setting up east of the Rockies in the Nov. 5-15 time frame.
However, to suggest trouble could be brewing, bears would need to force natural gas back below $2.903-2.852, said ICAP Technical Analysis’ Brian Larose. “As long as the bulls can keep natural gas above this band, I am inclined to treat any congestion near the highs as a pause in the uptrend.”
Larose still pegs $3.106, $3.181-3.192 and $3.242-3.330 as the next steps to the upside for the November contract should this pause prove short lived.
Meanwhile, traders on Friday were still digesting Thursday’s government storage data, though the tightening backdrop reflected in the latest report did little to revive prices. The Energy Information Administration (EIA) reported a 49 Bcf injection that lifted inventories for the week ending Oct. 16 to 3,926 Bcf. This is 345 Bcf higher than last year and 327 Bcf above the five-year average.
Analysts at The Schork Group said refills for the summer are veering onto the off ramp, with the market having replaced 111% of the gas that was delivered last winter.
Although most analysts had shrugged off containment concerns, there were some lingering concerns about inventories at salt facilities in the South Central region. The maximum capacity is estimated to be around 400 Bcf, and stocks were at 366 Bcf as of Oct. 9. However, a 6 Bcf draw for the Oct. 16 reference week likely had some traders breathing a sigh of relief.
“As you would expect, the salt region bore the brunt of shut-ins from Hurricane Delta,” The Schork Group analysts said.
They view the 6 Bcf draw in salt as “abnormal” given that for the middle of October, an injection in the range of 10-17 Bcf is typical. “Nevertheless, gas in salts is brimming.”
The Schork Group noted the market chatter than the next EIA report may be the last injection of the season. This may be “derivative of bulls talking their books,” but regardless of this posturing, “it deserves your attention,” analysts said.
As for what’s on deck for next week, Bespoke said it would not be a surprise to see the spead between November and December, which contracted from 48.5 cents on Monday to 22.4 cents by Friday, narrow even more into November expiration. The November contract rolls off the board on Wednesday.
“But the main thing we are seeing is the move toward what has the potential to be a very warm pattern beyond the opening days of November,” Bespoke said.
Though spot gas prices across the country were generally lower, Permian Basin markets suffered the biggest blow Friday.
Some cooler temperatures moving into the region over the weekend sapped a bit of weather demand. However, the main driver of Thursday’s massive 78.5-cent decline, a force majeure on El Paso Natural Gas (EPNG), was lifted Friday.
Nevertheless, Waha dropped another 92.0 cents to average minus 82.0 cents for gas delivery through Monday.
Meanwhile, Genscape Inc. said Permian production has remained suppressed, averaging around 9.8 Bcf/d in the last week-plus. For comparison, it had been running above 11 Bcf/d as recently as the end of August.
Other Texas markets also moved into the red Friday. Houston Ship Channel fell 16.5 cents to $2.835.
In the Midcontinent, prices were mixed. Most of the declines seen in the region were limited to a nickel, while gains along the Northern Natural Gas Pipeline were upward of 20.0 cents. Northern Natural Demarc averaged $3.215 for the three-day gas delivery.
The majority of hubs in Louisiana fell around 5 cents or so, as did those in the Southeast. The exception, once again, was Dominion Energy Cove Point, which jumped 32.5 cents day/day to $1.305.
Meanwhile, Dominion Energy Transmission Inc. (DETI) on Thursday said it would restrict deliveries to Columbia Gas Transmission (TCO) at the Cornwell, WV, interconnect to a level of 98 MMcf/d. This was because of TCO’s inability to receive gas from DETI at the interconnect.
DETI normally reports operational capacity of zero at the interconnect, according to Genscape, but it has a design capacity of 200 MMcf/d. For the 14 days prior to the outage, flows had averaged 143 MMcf/d and maxed at 197 MMcf/d.
“At the time of writing, scheduled capacity has fallen to 58 MMcf/d, a drop of 104 MMcf/d over two days,” said Genscape analyst Josh Garcia, who added that there is no estimated return to service.
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