• Natural gas futures reach new lows after large warm revision to long-term weather outlooks
  • Balances starting to loosen as production climbs, LNG intake drops
  • Northeast leads cash sell-off; Permian price pain seen through March at least

A major shift in weekend weather forecasts that may solidify this winter as one of the warmest on record sent Nymex natural gas futures plunging to fresh lows on Monday. The March Nymex contract tumbled 9.2 cents to settle at $1.766/MMBtu. April fell 8.8 cents to $1.804.

Cash markets also declined as light demand was on tap for the first part of the week. NGI’s Spot Gas National Avg. fell 10.5 cents to $1.660.

In a crushing blow to the natural gas market, weather models unanimously moved warmer over the weekend, with projected demand losses ranging from 15 to just over 30 gas-weighted degree days, according to Bespoke Weather Services. Although there are a couple of colder days coming at the end of this week, the pattern goes back very warm again as both the Arctic oscillation and the East Pacific oscillation stay positive into the latter part of the month.

“This cuts off the supply of colder air into the United States, keeping it bottled up in the polar regions,” Bespoke chief meteorologist Brian Lovern said. “As a result, it increases the risk that we see another top 10 warm month here in February, cementing this meteorological winter as one of the warmest in our data set.”

NatGasWeather noted that, like all winter so far, colder patterns in the day 13-16 forecast trended much warmer as they rolled into days six to 11. However, the day 13-16 forecast now is also quite mild versus normal across the eastern half of the United States, and the midday Global Forecast System run remained quite bearish with the pattern Feb. 17-24 even as it added back some of the demand it lost over the weekend.

The European model also added back some demand in its afternoon run, specifically with the weather system across the Great Lakes and Northeast Feb. 19-21, according to NatGasWeather. “It's far from frigid with this system, just a bit better this run.”

Unless colder weather materializes in major fashion, the loss of projected demand this month is most likely the final nail in the coffin for gas, preventing futures from rebounding in February and setting the stage for further declines, especially if warmer-than-normal weather persists into March, according to EBW Analytics Group. With the potential for additional coal displacement largely exhausted, this week’s demand loss is sufficient by itself to justify a further price decline of 10 cents or more.

“The psychological impact, however, could be just as significant,” EBW said.

The firm opined that as weather patterns have turned warmer as they move up in the forecasts, the market will likely ignore any cold signals unless the forecast shift is imminent. Furthermore, if this recent warm shift extends into March (as appears likely), too little time will be left in the withdrawal season to significantly affect the supply/demand balance.

Already, balances appear to be loosening a bit week/week. After sinking below 90 Bcf last week, Lower 48 production bounced back to around 92 Bcf by Monday, according to Bespoke.

Meanwhile, feed gas deliveries to U.S. liquefied natural gas export terminals fell to less than 8.1 million Dth on Monday, down from around 9.3 million Dth a week ago, as Cheniere Energy Inc. began planned maintenance on the Gillis compressor station that would limit its capacity to varying levels through Friday, including a full shutdown for two hours on Tuesday.

“In short, the balance is still rather tight, but not as impressive as we saw in the data last week,” Bespoke’s Lovern said. “As warm as the weather pattern is now looking, there can be more downside risk to prices yet.”

Northeast Leads Losses

A brief winter storm that hit the U.S. Northeast over the weekend failed to provide much support to cash prices late last week, and now with temperatures set to moderate in the coming days, cash markets cratered during Monday’s session.

Algonquin Citygate tumbled 94.0 cents, averaging $2.010 for Tuesday’s gas day. Transco Zone 6 NY dropped 8.0 cents to $1.760.

Losses across Appalachia were more uniform, capped at around 5 cents at the majority of pricing hubs.

On the pipeline front, Columbia Gas Transmission (TCO) is performing pigging on MXP Line 100 in West Virginia through Wednesday, with potential restrictions of up to 224 MMcf/d on Tuesday and Wednesday, according to Genscape Inc. The pigging is being performed in response to the forces majeure declared in late January on MXP Line 100, which were both expected to be resolved by Monday.

MXPSEG MA42 will be restricted to 1,553 MMcf/d during the two days, after having averaged 1,370 MMcf/d and maxed at 1,778 MMcf/d over the past 30 days, Genscape said. Full capacity through MXPSEG MA42 is not expected to be reinstated until work is complete, so flows on gas day Thursday could be impacted as well.

If the pipeline work does extend into Thursday, it would coincide with another weather system that is expected to send temperatures in the Northeast plunging to more seasonal levels. By Thursday night, temperatures across the Northeast and Ohio Valley will take a deep dive, sending overnight lows into the teens, according to AccuWeather. Breezy conditions will allow for wind-chill temperatures to dip even lower, into the single digits from Pittsburgh to Albany, New York, and below zero near the Canadian border.

"Not just the northern tier of the United States will be impacted by this cold. Places like Atlanta and Nashville will also experience temperature drops of 20 degrees or more," said AccuWeather senior meteorologist Eric Leister.

Over in the Southeast, Transco Zone 5 next-day gas fell 12.0 cents to $1.815, while benchmark Henry Hub slipped 7.5 cents to $1.810.

Losses in the Midcontinent and Midwest mostly clocked in at less than a dime, as did those in the eastern and southern parts of Texas. The exception was pricing hubs in West Texas, where prices bounced a bit from Friday but remained starkly discounted to other markets across the region.

Waha next-day gas rose 8.0 cents to average 40.5 cents for Tuesday’s gas day.

The deep discounts throughout the Permian Basin are seen continuing at least through the first quarter of 2020, according to Morgan Stanley Research. Relief appears to be unlikely until early 2021, when Kinder Morgan Inc.’s 2.0 Bcf/d Permian Highway Pipeline (PHP) is expected to begin service, followed by MPLX LP’s 2.0 Bcf/d Whistler Pipeline in the second half of 2021.

However, the road to getting PHP built has not been easy, and Kinder Morgan is facing yet another roadblock after the cities of Austin and San Marcos, Travis and Hays counties, along with the Barton Springs Edwards Aquifer Conservation District and affected landowners, filed a lawsuit against the company, as well as the U.S. Department of Interior and its U.S. Fish and Wildlife Service.

Meanwhile, debottlenecking of Mexican pipeline capacity south of the border “is a wildcard” and although it could add an aggregate roughly 850 MMcf/d of effective incremental takeaway in 2020, it remains highly uncertain, according to the Morgan Stanley team led by Devin McDermott.

Whether any additional buildout occurs after 2021 remains unclear. Kinder Morgan has floated the idea of another 2 Bcf/d pipeline, to be called Permian Pass, but management has indicated that commercial discussions cooled a bit after producers last year issued 2Q2019 guidance and tightened up their capital plans. Although the midstreamer still sees a need for additional takeaway out of the Permian, “it’s probably not as soon as we thought this time last year,” CEO Steven Kean said.

Morgan Stanley expects tightness to re-emerge by early 2024, essentially seeing a need for an additional 2 Bcf/d of eastbound pipeline every two to three years thereafter through the end of the decade, totaling around 6 Bcf/d of additional capacity beyond PHP and Whistler.

“Lack of producer willingness to underwrite long-term commitments remains a key impediment, although consolidation of smaller operators, where flaring is more acute, could catalyze commercial support,” the Morgan Stanley team said. “We estimate California renewables could displace around 50% (~1.7 Bcf/d) of western gas flows out of the Permian by 2030, adding to the need for further eastbound pipe capacity.”