“Insanely tight” supply/demand balances notwithstanding, weather dominated natural gas forward markets for the Oct. 29-Nov. 4 period. With an extremely mild forecast for the next two weeks at least, prices for December and the remaining months of winter fell sharply. Smaller, single-digit losses were seen further out the curve.
The steep declines mimicked the slide along the Nymex futures curve, where the Henry Hub December contract slid around 25 cents to $3.046, and the balance of winter lost 23.0 cents to reach around $3.10. Losses were less severe for the summer and beyond, with declines of less than a nickel.
In the past week alone, the long-range outlook has shaved considerable demand from the forecast, and the latest model runs were no exception. Bespoke Weather Services said there continues to be a pattern that is “very hostile toward any notable cold anywhere that matters much for natural gas consumption.”
The forecaster said the 15-day forecast is now almost a full 80 gas-weighted degree days warmer than normal, which is “quite incredible for just a 15-day period.” This amounts to about 120 Bcf less natural gas demand than would be expected with a normal weather pattern, according to Bespoke.
“We currently project that this will be the fifth warmest November of all time, but that still assumes normal beyond Day 15, which, for now, looks unlikely,” the forecaster said. “With warmth favored into the 16- to 20-day time frame, we could at least overtake November 2009 for fourth on the list, behind just 2001, 1999 and 2016.”
The warm start to winter has helped to eradicate any winter risk premiums in the Nymex futures strip, with the so-called widowmaker spread sitting Wednesday at a meager 15 cents. As EBW Analytics Group pointed out, if market observers felt there was a danger of exhausting available supplies, the March contract would trade at a considerable premium to April to ensure supply adequacy at the end of winter.
“Often, there is greater concern early in the winter of the risk of a start-to-finish ultracold scenario, which then abates later in the winter when this most extreme bullish outcome is taken off the table,” EBW said. “The first week of November, however, appears a little early to significantly de-risk the chances for a tight winter, particularly this year, with uncertain effects of the structural shift to increased working-from-home and likely associated structural increases in space heating demand.”
Genscape Inc. senior natural gas analyst Eric Fell agreed the new normal of working from home amid Covid-19 may upend traditional market behaviors during winter. So far, however, the impacts have not been what some may have expected.
Participating in The Desk’s online energy chat Enelyst, Fell said many market observers continue to miss the significant growth in residential/commercial (res/com) demand per heating degree day over the past few years. Reported res/com demand last winter was more than 2 Bcf/d stronger per gas-weighted heating degree days (GWHDD) than in the 2011-2016 time frame. Still, it’s not clear what impact the pandemic would have on res/com.
“Some have suggested big increases, but so far reported data since April actually shows a decline in res/com,” Fell said. Specifically, the decline in commercial demand is bigger than the increase in residential demand per GWHDD.
“But that is summer res/com data. There’s no space heating demand in July and August, so we could see an increase in the winter as residential space heating is about three times as sensitive to GWHDDs as commercial space heating.”
Red Versus Blue Maps
With some early season cold that descended as far south as Texas last week, increased residential heating may have factored into the latest big miss in the storage data. On Thursday, the Energy Information Administration (EIA) said U.S. inventories fell by 36 Bcf to 3,919 Bcf, which is only 200 Bcf higher than last year at this time and 201 Bcf above the five-year average.
The reported withdrawal, the first weekly net draw during the month of October in more than 10 years, came in well above market expectations that coalesced around a draw closer to 30 Bcf. NGI had projected a 28 Bcf pull.
However, the biggest surprise was that the entire net change occurred in the South Central region, with the mix of injections and draws in other regions essentially holding stocks steady. The EIA said the South Central’s reported 36 Bcf draw consisted of a 23 Bcf pull from nonsalt facilities and a 12 Bcf draw from salts.
Fell noted that production has been well off its year-ago record highs, and exports in the form of liquefied natural gas (LNG) and flows to Mexico also have been at record levels. To be sure, feed gas deliveries to U.S. terminals jumped above 10 Bcf on Oct. 31 and have remained at that level since.
“This earlier-than-normal start to the withdrawal season is due to a very tight supply/demand equation along with a strong cold shot over the last full week of October,” the analyst said. “We continue to model a tight market over the winter, but not as tight as recent weekly stats.”
That’s mainly because of the sharp turn in the weather models. Fell noted the 100 Bcf-plus drop in projected demand for the near term and said winter weather can be volatile, with about 2 Tcf of variability in winter weather-related demand.
“Even in an election week, the ‘red versus blue’ maps that matter the most to the natural gas market are the ones being produced by various weather agencies,” he said.
New Forward Look Points
In an ongoing effort to provide clarity to the market, NGI has added seven pricing locations to its extensive Forward Look product.
For the Cheyenne Hub, the addition reflects the important pricing interconnect between seven pipelines on the Colorado/Wyoming border. Opal, meanwhile, is the most liquid daily physical trading hub in the entire Rockies.
With the additions, the Forward Look dataset now contains 67 curves by month out 10 years as both basis and fixed prices.
The timing of two of those points, in particular, could not be better. The Wamsutter West expansion project came online Sunday (Nov. 1), bringing additional East-to-West capacity to Dominion Energy’s Overthrust Pipeline and enhanced backhaul capability for Rockies Express Pipeline (REX) flow points.
REX’s Wamsutter interconnect with Overthrust has increased its delivery capabilities by around 330 MMcf/d and contracted for 117 MMcf/d in firm transportation capacity in the East-to-West direction on Overthrust, according to Genscape.
“This expansion could potentially stoke more competition between Opal and Cheyenne hubs by helping provide growing Denver-Julesburg production with access to more premium markets in the Pacific Northwest and Northern California via PG&E Citygate and Malin while other Rockies basins continue production declines,” said Genscape analyst Matthew McDowell.
Immediately upon going into service, deliveries from REX onto Overthrust at Wamsutter jumped by roughly 170 MMcf/d, according to Genscape. They have continued to fulfill the increased Westbound capacity.
On Wednesday, Cheyenne Hub December prices stood at $3.012, down from $3.25 at the start of the month, according to Forward Look. The balance of winter averaged $3.028, while prices for next summer (April-October) averaged $2.662. The winter 2021-2022 strip averaged $3.013.
By comparison, Opal December stood at $3.587, and the balance of winter stood at $3.477. However, by next summer, the spread between the two hubs contracts quite a bit. Opal’s summer 2021 strip averaged $2.771, only about 11.0 cents above Cheyenne Hub. The winter 2021-2022 package also trims its premium to only 33.0 cents, averaging $3.343.
