MVP failure this winter for Transco Hubs potentially upside; Preliminary natural gas prices

Natural gas forwards, mirroring Nymex futures, trended lower during the Oct. 11-18 trading period, although price action in Western hubs again diverged from the rest of the Lower 48. NGI outlook data.

Henry Hub fixed prices for November delivery fell 32.1 cents to $3.059/MMBtu, and first-month discounts of around 30-50 cents were the norm for most regions.

Western nervousness

Roughly a year after the intense winter swings, price action in the central west, especially in California, continued to be nervous.

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SoCal Citygate reported weekly earnings of $2,000 or more for the November, December and January contracts.

Malin picked up $1,270 for January week/week to reach plus-$6,224, while Opal similarly jumped $1,158 higher to plus-$6,098.

WITH logout of regulators Driven by increased working capacity for Aliso Canyon storage facilities, the Southern California market is heading into winter 2023/24 with a better supply picture than a year ago, according to East Daley Analytics.

“Combined with a better view of pipeline flows, the additional storage could help the state avoid a repeat of last winter’s swings,” East Daley analysts said in a recent note.

Analysts noted that in the winter of 2022/23, severe storms and pipeline constraints in the El Paso Natural Gas system helped create a recipe for regional price spikes.

“Pacific Coast storage has lagged behind the five-year average for most of 2023 and finally settled to normal seasonal levels in late September,” East Daley analysts said.

Meanwhile, updated forecasts from Maxar’s Weather Desk on Thursday showed model disagreement on the extent of cold expected for the western Lower 48 heading into the last week of October.

“A pair of troughs settles in the West in the early six to 10 days, and their interaction is the source of the differences in the models,” Maxar said. The American model “interacts with these features faster” than the European data set “and thus provides cooler conditions.” Our forecast is a compromise of the models,” and pointed to below-normal conditions for the Rockies during the second half of the period.

The 11- to 15-day period also featured model divergence in recent Thursday runs, according to forecasters.

Maxar continued to call for “below-normal temperatures in the Mid-Continent to begin migrating eastward” in that time frame. “Meanwhile, the ridge is expected to return to above normal temperatures to the west, and this is particularly the case in the second half.”

Will the MVP delay affect prices?

As for the supply outlook, Appalachian producers will have to wait a little longer for new offtake capacity from the long-delayed Mountain Valley Pipeline (MVP). The operator told regulators it now expects the project to enter service in 1Q2024 place by the end of the year.

Project co-sponsor Equitrans Midstream Corp. in a Form-8K filing this week with the Securities and Exchange Commission, he pointed to “unforeseen factors” that have “materially affected the pace of construction” of the Appalachian-to-Southeast pipeline.

The MVP is designed to deliver gas from the Marcellus and Utica Shales to interconnect with Transco (aka the Transcontinental Gas Pipe Line) at Station 165 in Pittsylvania County, VA.

East Daley analyst Alex Gafford said the company had predicted delays given MVP’s “incredibly tight timeline” to bring the project into service in 2023.

“We are currently projecting that MVP will be operational on April 1st, and we will likely stick to that estimate,” Gafford told NGI. “As a result, we have no gas or diversion issues captured in our model in our North East supply and demand outlook.

“Our view is that on April 1, the pipeline will initially only fill to about 400 MMcf/d due to downstream constraints” on Transco.

Wood Mackenzie analysts Colette Breshears, Devin Cao and Randall Collum similarly pointed to restrictions in flow direction as a limiting factor for the rise in Appalachian runoff when the MVP becomes operational.

“Most of the gas from the MVP will fill local demand in Zone 5 and push back gas flowing south from eastern Pennsylvania, with only a small portion increasing transport south along Transco to Zone 4” and the Gulf Coast, Wood Mackenzie analysts said in a note. to NGI.

Based on historical flow patterns, the firm modeled 0.6 Bcf/d of net export capacity with the project online versus projected pipeline capacity of around 2 Bcf/d.

“Implied volumes through Station 165 during peak demand have averaged roughly 1.5 Bcf/d over the past several years,” the Wood Mackenzie team said. “Using the announced project capacity of 2.1 Bcf/d of Station 160 South, only about 0.6 Bcf/d remains for net MVP exports.”

Wood Mackenzie modeling based on the MVP start-up in December 2023 would see regional production remain stagnant or decline slightly through the winter. Analysts say that forecast is not expected to change much as the pipeline is now delayed.

“Nationally, we see related gas plays continuing to grow production, with dry gas showing stagnant to declining production,” they said.

In terms of price impacts, Wood Mackenzie analysts said they expect the delayed MVP start to generally put bullish pressure on the Transco 5 zone and bearish further upstream in Appalachia.

Zone 6 Transco prices would see “smaller but related” bullish pressure amid higher Zone 5 demand, while Zone 4 would also see bullish pressure as Zone 5 “depends on increased Zone 4 imports during peak winter,” analysts said . “These nodes are chosen to be representative of connected nodes in each region, but it outlines how we consider the effects of delay.”

Eastern Gas South’s leading monthly basis fell 2.1 cents to minus $1,281 during the Oct. 11-18 period. Fixed prices for November at the hub fell 34.0 cents for the week, down more than 16% from the 9.5% week/week discount at the Henry Hub, Looking ahead the data show.

Meanwhile, the Transco Zone 5 base sold off early in the curve but strengthened in early 2024. The January base rose 13.8 cents there to end the period at plus-$3,731.

Back under $3

Nymex futures rallied throughout the Oct. 11-18 trading period, including consecutive double-digit first-month declines last Friday (Oct. 13) and over the weekend (Oct. 16). November fell 9.9 cents to settle at $2,957 on Thursday.

The November contract extended its losing streak on Friday, losing another 5.8 cents to settle at $2,899.

Earlier in the month, a bullish surprise from the US Energy Information Administration’s (EIA) weekly storage report sent the November contract over the $3 psychological barrier. It was fitting, then, that a bearish divergence in the repository’s latest release provided the final impetus for the first month to slip back into sub-$3 territory.

The EIA on Thursday reported an injection of 97 Bcf for the week ending Oct. 13, which came in at the upper end of market expectations.

“After three weeks of the EIA’s storage report being lower than most market estimates, we see it coming in significantly higher than expected this week,” Wood Mackenzie analyst Eric McGuire said of the latest print. “Our primary miss was in the south center where both salt and no-salt were higher than we expected. It was also the South Central region that was lower than expected in previous weeks.”

Compared to degree days and normal seasonality, the latest EIA report was about 3.5 Bcf/d below the previous five-year average, according to the analyst.

In a note to clients, NatGasWeather pointed to two possible explanations for the bloated print from the EIA. For one thing, it could be offsetting the unexpectedly lean builds reported in recent weeks, the firm said.

“Another reason is that temperatures were exceptionally pleasant over Texas last week for the first time since last spring, and that led to a massive build of 40 Bcf in the South Central EIA region, greater than expected,” NatGasWeather said.

An initial cold spell over the northern US during the period also likely “didn’t lead to much demand” as lows only reached the upper 30s to 40s, the firm added.

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