After a drop in production helped rally prices to start the work week, natural gas futures reversed sharply Tuesday amid reports of the interrupted supply coming back online. In the spot market, potential record-setting heat expected in the Southeast by the weekend proved insufficient as a catalyst for higher day-ahead prices; the NGI Spot Gas National Avg. skidded 3.5 cents to $2.090/MMBtu.

Coming off a 4.2-cent rally on Monday, the June contract tumbled 6.0 cents Tuesday to settle at $2.613. July settled at $2.641, down 5.8 cents, while August slid 5.8 cents to settle at $2.656.

The swing lower in prices from Monday likely stemmed from a day/day shift in the fundamentals, including additional production returning with the resolution of maintenance issues in West Virginia and a decline in liquefied natural gas (LNG) exports, Powerhouse Vice President David Thompson told NGI.

Bespoke Weather Services similarly pointed to fundamentals to explain Tuesday’s sell-off.

“The weakness came mostly from production returning after the weekend drop-off,” the firm said. “It’s still not back to the highs,” but after the revisions, Tuesday “will be back up solidly since Sunday.” LNG exports were down in the latest data, “assisting the bearish case somewhat in terms of keeping daily balances looking weak.”

Power burns, on the other hand, trended more bullish Tuesday, which could help keep a floor for prices at the $2.60 level, “especially with the heat that is coming the rest of this week into the first half of next week,” according to Bespoke.

Genscape Inc. said flow data Tuesday indicated that operational capacity at the Equitrans Meter 24605 had been fully restored following a recent force majeure related to issues at the MarkWest Mobley Plant in West Virginia. As of Tuesday’s timely cycle, Equitrans flows from the Mobley facility had rebounded back up to 550 MMcf/d, higher than the prior 14-day average, according to analyst Anthony Ferrara.

Elsewhere in the region, Columbia Gas Transmission (TCO) notified shippers Tuesday that operational issues associated with an outage on a line feeding the Hopedale Fractionation Plant had been resolved. The outage temporarily reduced supply on the TCO system by around 2.1 million Dth, according to the pipeline’s estimates.

Based on month-to-date production trends as of late last week, Energy Aspects said in a recent note to clients “it would be unwise to gloss over the impacts of a heavy maintenance season” on supply during the shoulder months.

“Before the start of May, our estimate for month/month growth was 0.5 Bcf/d,” the firm said. “Given an essentially flat production reading” for last week, “there is some risk that the number will fall toward 0.3-0.4 Bcf/d month/month, even assuming a moderate clip of weekly gains on the order of 0.2-0.3 Bcf/d through the end of the month.

“Looking at basin-level production flow data, no single region stands out as an outperformer,” according to Energy Aspects. “The typical driver of sequential growth, Appalachia, has registered a 0.2 Bcf/d month/month decline on a month-to-date basis, according to flow data.

“Permian production has come off month/month, according to our sample, with a 0.5 Bcf/d gap between this month’s peak daily production and its lowest, as we have seen more maintenance and also some price-responsiveness from producers choking back/shutting in output.”

Looking longer-term, analysts at Tudor, Pickering, Holt & Co. (TPH) expect demand to slow in the 2021-2022 time frame, necessitating a pullback in production from gas-focused regions.

“Despite annual supply growth of around 8 Bcf/d over the past two years, natural gas has avoided a major pricing collapse thanks to equally impressive growth on the demand side of the ledger,” the TPH analysts said. “The problem is roughly 50% of demand growth has been driven by exports” via LNG terminals and to Mexico via pipeline. These exports “are positioned to drop off materially, while supply growth, driven by associated volumes, continues chugging.

“As we move into the LNG air pocket, we’re forecasting associated gas growth of around 3.2 Bcf/d, meaning associated volumes will be more than enough to satiate incremental demand growth,” according to the analysts. “As a result, we believe around 3 Bcf/d will need to drop out of our base case production forecast, with gas-directed basins moving to maintenance capital and pricing remaining in the $2.50 range to draw in incremental coal-to-gas switching.”

However, by 2023-2024, a “dramatic reversal” is likely as the second phase of LNG capacity expansions hits, potentially driving average annual demand growth of over 5 Bcf/d, according to the TPH team.

“If producers are unwilling to commit to new pipe in the interim, particularly out of the Permian, it’s quite possible supply adds struggle to keep pace with demand, driving gas prices materially higher.”

More Permian Price Pain

Spot prices in the Permian Basin have struggled over the past couple trading days, dropping into the negatives and recalling the extreme downward pressure observed earlier in the shoulder season.

Tuesday was no exception, as most points in the region dropped deeper into negative territory. Waha fell 22.0 cents to average minus 55.5 cents.

The weak pricing in West Texas has coincided with a two-day maintenance event limiting Permian outflows on Northern Natural Gas (NNG), according to Genscape analyst Joe Bernardi.

“Station maintenance on NNG limited capacity at its Brownfield North and Mitchell to Gaines allocation groups” starting with Tuesday’s gas day and expected to last through Wednesday, the analyst said. “Permian production onto NNG showed a corresponding drop of about 250 MMcf/d in the early cycles” for Tuesday.

Meanwhile, further west a one-day planned maintenance event on the El Paso Natural Gas (EPNG) system could impact more than 300 MMcf/d of San Juan production volumes starting Wednesday, according to Bernardi.

“EPNG is working on its Line 1202, requiring a shut-in of its receipt points connecting to Transwestern and to Williams’ Milagro gas processing plant,” Bernardi said. “El Paso receives volumes that originate as San Juan production from Transwestern at their interconnect. Together, these two locations have averaged 320 MMcf/d in the past month. Capacity out of the area should be available on Transwestern either toward the California border or toward the Phoenix metro area for potential reroutes.”

With maintenance impacting the region, prices were mixed across the Southwest Tuesday. El Paso S. Mainline/N. Baja jumped 63.0 cents to $1.275, while Transwestern San Juan jumped 86.0 cents to $1.300. Kern Delivery gave up 3.5 cents to average $2.000.

Elsewhere, Southeast prices posted discounts Tuesday, though more intense heat expected by the end of the week could present upside for prices in the region. Transco Zone 4 slid 9.0 cents to $2.610.

Starting later this week and continuing through the Memorial Day weekend, heat in the Southeast could challenge daily and monthly records, according to a forecast from Maxar Earth Intelligence Solutions. This includes temperatures in the mid to upper 90s in Atlanta and potentially triple-digit heat in areas stretching from the Florida Panhandle into the Carolinas, the forecaster said.

“Memorial Day is often referred to as the unofficial start of summer, and this year more than qualifies in the eastern half of the U.S.,” Maxar’s lead meteorologist Bradley Harvey said. “This will be a prolonged and record-breaking heat event as a strong ridge over the Southeast holds firm through the rest of May.”

The weaker pricing in the Southeast Tuesday matched similar declines observed throughout much of the Gulf Coast, Texas, Midwest, Midcontinent, Northeast and Appalachia, with the hot pattern expected to develop by the holiday weekend not enough to tease out more buying interest. Benchmark Henry Hub fell 5.5 cents to $2.650.