After pulling off a stunning rally in the first week of August, natural gas forward prices were mixed for the Aug. 6-12 period as easing demand pummelled East Coast prices while soaring temperatures prompted sharp spikes out West.

Northeast Total Gas Demand

Meanwhile, liquefied natural gas (LNG) demand, which ramped up a bit over the past week, is seen playing an increasingly important role in balances in the coming months, with swelling storage inventories necessitating an outlet for supply.

On a national level, the September contract ultimately averaged flat for the period at $1.886, while October slipped a penny to average $1.976 and the upcoming winter (November-March) gained a penny to average $3.070, according to NGI’s Forward Look.

Taking price action on the East and West coasts out of the equation, most U.S. forward markets moved in sync with Nymex futures, which settled down a bit after the prior week’s unusually wild ride.

The September contract managed to put up some decent swings of more than a nickel on Aug. 7 and 10, but then floundered back and forth throughout the rest of the Aug. 6-12 period. The prompt month ultimately settled Wednesday at $2.152, down about 2 cents from Aug. 6, while the balance of summer slipped a penny to $2.225. Prices through the rest of the curve were marginally higher on the week, with the Nymex winter strip climbing to $2.950 and summer 2021 moving to $2.690.

There appears to be a growing consensus the gas market is on the cusp of a major flip in sentiment as projections for lower production and stronger demand are likely to boost prices this winter. However, there could be several weeks ahead before some of those changes in the supply/demand balance take shape.

‘Storage Ratchets’

Storage inventories already are trending well above historical levels, with the latest government storage data disappointing the market with a higher-than-expected injection. The Energy Information Administration (EIA) said that inventories for the week ending Aug. 7 climbed by 58 Bcf, a figure that fell well within the 42-65 Bcf range of estimates ahead of the report, but was a few Bcf higher than consensus. 

“It was a very mild week with good wind,” and a 58 Bcf injection is “right on neutral” from a supply/demand perspective given the weather, said one market observer on The Desk’s online energy platform Enelyst.

The analyst noted that last September and October, the gas market saw injections that were 4 Bcf/day loose, “or worse.” This September and October, however, LNG is rebounding and production is starting to roll over. “There will be a big year/year difference.”

After sinking well below 3 Bcf/d earlier this summer, LNG feed gas volumes have steadily come in well above 4 Bcf/d over the past week and barring any major new impacts related to Covid-19, analysts see demand growing in the coming months to perhaps as much as 8 Bcf/d by the end of the year.

Analyst Stephen Schork also pointed out that “Wall Street loves natty right now. Funds are holding their largest bull position since optionsellers.com fiasco in November 2018.”

Last year, the EIA recorded a 51 Bcf injection for the similar week, while the five-year average stands at 44 Bcf.

Broken down by region, the Midwest added 26 Bcf into inventories, and the East added 20 Bcf, according to EIA. Mountain and Pacific stocks each grew by less than 5 Bcf, while the South Central region reported a net injection of 5 Bcf, which included a 1 Bcf build into salt facilities and a 5 Bcf build in nonsalts.

Shah questioned whether the market would be “hitting storage ratchets” in late September given that East and Midwest inventories still were sitting at their highs. “If so, we could see cash in those markets fall apart.”

Tudor, Pickering, Holt & Co. (TPH) analysts similarly pointed out that the “South Central and Midwest are on the wrong side of the five-year range, and the East is knocking on the door.”

While aggregate storage levels capture most of the mindshare, the TPH team thinks regional storage may begin to become topical, as five-year average build profiles would push the Midwest through capacity, with the East reaching 99% and South Central 97%.

“To make matters worse, we’re modeling above-normal injections the rest of the way, in part due to reduced power burn as gas prices are pulling coal back into the stack,” said analysts.

For the next EIA report, TPH is modeling a build of 44 Bcf, which is in line with the five-year average injection of 45 Bcf. However, with cooler weather ahead, analysts see power generation dropping back below 40 Bcf the following week, from around the current 43 Bcf level.

Also on the radar is Cheniere Energy Inc.’s October cancellation deadline on Thursday (Aug. 20), which should provide a window into October feed gas demand, “which we’re modeling at 7.5 Bcf/d, more than 60% above current levels,” TPH said.

Total working gas in storage as of Aug. 7 stood at 3,332 Bcf, which is 608 Bcf higher than last year at this time and 443 Bcf above the five-year average of 2,889 Bcf, EIA said.

Traders appeared to not want to move the needle much following the EIA report, as the September contract moved within a tight 6.6-cent range before ultimately settling 3.0 cents higher day/day at $2.182.

Mobius Risk Group said as is often the case, attention may quickly turn to next week’s EIA report, where early indications suggest a generally similar dynamic could play out. With early estimates in the 40 Bcf range, the firm said “a build of less than 45 Bcf could be enough to generate a better bid in the market, and a result greater than 55 Bcf would likely be large enough to meaningfully pressure the front of the curve.”

While the current state of inventories does bring some containment risk back into the market, Bespoke Weather Services chief meteorologist Brian Lovern said the bullish thesis for winter looks sound, weather dependent of course. “It’s also disconnected from what the front does, of course. As in, we could completely fill, and have containment issues, all while not killing the bullish winter thesis.”

Nosediving Northeast

After a much hotter-than-normal July, the stage was set for an active tropical season, and August got off to a busy start on the East Coast. Hurricane Isaias slammed North Carolina as a Category 1 storm before heading up the coast, causing heavy winds, rain and widespread power outages that sapped demand. Over the past week, though, heat and humidity returned, and power restoration efforts largely were completed, leading to a surge in demand far above year-ago levels, according to Criterion Research LLC.

The Houston-based firm reported that total Northeast demand soared close to 17,000 MMcf/d on Tuesday (Aug. 11), sharply higher than year-ago levels of around 12,000 Bcf/d. However, with temperatures falling back to the 70s and 80s by Thursday, regional demand headed back toward 14,000 MMcf/d and was expected to slip further in the coming days to below 12,000 MMcf/d before recovering back above 13,000 MMcf/d by Aug. 25. Last year, the Northeast experienced a late-season heat wave that boosted demand to nearly 17,000 MMcf/d between Aug. 18 and 25, Criterion noted.

A cooler outlook for the remainder of August in the East appears to have minimized the impacts of lower production. On Wednesday, Genscape Inc. reported that the region was leading the large drop in Lower 48 output seen this week, with production down 1.5 Bcf/d from maintenance on the Columbia Gas Transmission (TCO) MXP Line 100 in West Virginia. Production fell 730 MMcf/d in Ohio, 250 MMcf/d in West Virginia and 374 MMcf/d in Northeast Pennsylvania, according to Genscape. The TCO outage is scheduled to last until Sunday (Aug. 16).

The other roughly 800 MMcf/d in dropped production was mostly spread between the Gulf Coast (down 147 MMcf/d), Texas (off 282 MMcf/d), the Midcontinent (down 106 MMcf/d) and the Permian Basin in New Mexico (off 156 MMcf/d), partially because of pipeline maintenance, Genscape said.

As for the forward curves, Transco Zone 6 NY prices were down about 13.0 cents through the rest of summer, with September sliding to $1.409 and the balance of summer (September-October) falling to $1.440, according to Forward Look. The winter strip (November-March) was steady at $3.950, while summer 2021 (April-October) climbed 1.0 cent to $2.300.

Upstream in Appalachia, Dominion South September was down 11.0 cents from Aug. 6-12 to reach $1.212, as was the balance of summer, which hit $1.250. The winter strip was flat at $2.490, and the summer 2021 strip gained 1.0 cent to hit $2.150.

At the same time weather models are starting to hint at cooler patterns along the East Coast, conditions are expected to get progressively hotter out West. NatGasWeather said with the core of the hot upper ridge over the West, highs were forecast to “easily reach” the 90s and 100s across most states, with the hottest conditions over California and the Southwest.

The scorching outlook drove forward prices higher across the region. SoCal Border Avg. prices for September shot up 28.0 cents from Aug. 6-12 to reach $2.302, and the balance of summer jumped 18.0 cents to $2.250, Forward Look data show. Gains were smaller further out the curve, with the upcoming winter strip climbing 6.0 cents to $3.220 and summer 2021 rising 5.0 cents to $2.590.

Increases extended into the Rockies, where Northwest Sumas September was up 10.0 cents to $2.014, the balance of summer edged up 7.0 cents to $2.10, the winter tacked on 6.0 cents to $3.640 and summer 2021 was up only 1.0 cent to $2.290.