With September lining up to deliver plenty of late-season heat, and with storage trends pointing to a shrinking Lower 48 inventory cushion, regional natural gas forwards advanced during the Aug. 24-30 trading period, NGI’s Forward Look data show.
Fixed prices at benchmark Henry Hub climbed 20.4 cents week/week to end at $2.793/MMBtu for October delivery, and fixed price gains of around 20 cents or more were the norm throughout the Lower 48.
Weather-driven demand during the upcoming week will “rebound…to strong levels as hot high pressure returns to cover most of the U.S. with highs of upper 80s to 100s, including mid- to upper 90s for chicago and lower 90s for a few days for New York City,” NatGasWeather told clients Thursday. “This also includes heat continuing over Texas and nearby states with highs of 90s and 100s. However, wind energy generation across the U.S.” for the period “is expected to be much stronger than this past week.”
Longer-range forecasting was also favoring “bullish weather sentiment continuing Sept. 13-20 as much of the U.S. remains warmer than normal for a little stronger than normal demand,” the firm added. However, “the risk is the data trends a little cooler in time.”
Midweek Pop
Nymex futures saw relatively little net change day/day as the September contract rolled off the board at the start of the week. On its last day Tuesday, September shed 2.3 cents to settle at $2.556.
However, on its first day as the new front month, October popped 13.4 cents on Wednesday. A 2.8-cent slide on Thursday saw October preserve most of the midweek gains.
EBW Analytics Group analyst Eli Rubin highlighted a number of factors that could have contributed to Wednesday’s rally.
These included “weaker-than-feared demand destruction from Idalia and a delayed reaction to the weekend heat surge following September contract expiration,” Rubin said. “Trader murmurs also indicate a short squeeze in bearish spreads may have led to an uptick in buying activity at the front of the curve.”
In terms of assessing market impacts from Hurricane Idalia’s destructive path through Florida, total natural gas demand for the state for Wednesday, when the storm made landfall, was revised higher by around 300,000 MMBtu/d, according to Wood Mackenzie analyst Kara Ozgen. This indicated a roughly 400,000 MMBtu/d day/day decline, the analyst said.
“Today’s nominations show demand almost fully rebounding,” Ozgen said. The firm’s estimates pointed to a roughly 87,000 MMBtu/d day/day cut to demand in Georgia.
Not An Anomaly
Meanwhile, the U.S. Energy Information Administration (EIA) on Thursday reported a 32 Bcf injection into domestic storage for the week ending Aug. 25, on the higher side of pre-report estimates.
Still, the 32 Bcf print, though ostensibly not as lean, doesn’t necessarily undermine the bullish sentiment inspired by the prior week’s number.
For one, the latest injection further trimmed the surplus to the five-year average, which dropped from 268 Bcf down to 249 Bcf. The last eight EIA reports have reduced the year-on-five-year cushion, data show.
What’s more, the latest EIA injection figure, despite being notably larger, actually corroborates the tightness implied by the bullish print that preceded it, according to Wood Mackenzie analyst Eric McGuire.
At first blush the 32 Bcf print “seems to point to last week’s plus-18 Bcf as anomalous,” McGuire said. “I believe it actually confirms last week’s number. The largest surprise in last week’s number was the 8 Bcf draw in nonsalts, which pointed to a weather normalized tightness of minus-2.3 Bcf/d for the South Central region.
“I initially discounted this as I did not believe the South Central tightened by minus-0.8 Bcf/d week/week,” the analyst added.
However, this week’s EIA report showed another hefty South Central draw of 22 Bcf, including 12 Bcf withdrawn from nonsalt storage.
“This draw indicates that the South Central tightened further week/week and now sits at minus-2.6 Bcf/d tight compared to degree days and normal seasonality,” McGuire said. “So on both an outright level and from a tightness perspective, this week does confirm last week’s surprisingly large draw in the South Central.”
The natural gas market has been running “well above” 2.0 Bcf/d tighter versus five-year norms, EBW’s Rubin estimated in a recent research note.
“Eventually, tightening fundamentals could yield upside,” Rubin said.
Still, unless cold temperatures arrive early in the heating season, “lofty Nymex winter risk premiums may prove difficult to sustain — particularly if production regains momentum into winter,” according to Rubin.
Haynesville Shale production has fallen back from highs observed in the spring, but these declines have been offset by higher volumes flowing out of the Permian Basin, the analyst said.
“As the 0.5 Bcf/d Whistler Pipeline expands Permian takeaway capacity into September, rising Permian supplies may continue to partially offset falling production elsewhere,” Rubin said. “Still, the 30-45 day period could feature the appearance of declining production into the first half of October as producers shape their production profile to take advantage of steep contango across the Nymex forward curve.”
Appalachian producers, as an example, have an “enormous financial incentive” to defer production from October to November where they can, the analyst said.
Fixed prices at Eastern Gas South were trading at $1.120 for October, versus $1.817, according to Forward Look. October basis at the location ended the Aug. 24-30 period at minus-$1.676, with November basis at minus $1.364.
The post September Heat Bolsters Natural Gas Forward Prices; Storage Data Seen Confirming Tightness appeared first on Natural Gas Intelligence
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