Natural gas forwards, mirroring Nymex futures, trended lower during the Oct. 11-18 trading period, though once again price action at hubs in the West diverged from the rest of the Lower 48, according to NGI’s Forward Look data.
Henry Hub fixed prices for November delivery fell 32.1 cents to $3.059/MMBtu, and front month discounts of around 30-50 cents were the norm for most regions.
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West Jitters
Roughly a year removed from some intense winter spikes, price action at Western hubs, particularly in California, continued to prove jittery.
SoCal Citygate posted gains of $2.000 or more week/week for the November, December and January contracts.
Malin picked up $1.270 week/week for January to reach plus-$6.224, while Opal similarly jumped $1.158 higher to plus-$6.098.
With regulators signing off on increased working capacity for the Aliso Canyon storage facility, the Southern California market is heading into the 2023/24 winter with an improved supply picture versus a year ago, according to East Daley Analytics.
“Combined with an improved outlook for pipeline flows, the additional storage could help the state avoid a repeat of last winter’s volatility,” East Daley analysts said in a recent note.
In the 2022/23 winter, severe storms and pipeline constraints on the El Paso Natural Gas system helped create a recipe for regional price spikes, the analysts noted.
“Pacific Coast storage has lagged the five-year average for most of 2023 and finally caught up to normal seasonal levels in late September,” the East Daley analysts said.
Meanwhile, updated forecasts from Maxar’s Weather Desk Thursday showed model disagreement on the extent of cold expected for the western Lower 48 heading into the final week of October.
“A pair of troughs settle into the West early in the six- to 10-day period, with their interaction being the source of divergence in the models,” Maxar said. The American model “interacts with these features more quickly” than the European dataset “and thus supplies 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 runs Thursday, according to the forecaster.
Maxar continued to call for “below normal temperatures in the Midcontinent to start migrating toward the East” during this time frame. “Meanwhile, a ridge is expected to return above normal temperatures to the West, and this is especially the case during the second half.”
Will MVP Delay Affect Prices?
Turning to the supply outlook, Appalachian producers will have to wait a while longer for new takeaway capacity from the long-delayed Mountain Valley Pipeline (MVP). The operator told regulators that it now expects the project to enter service in 1Q2024 instead of by year’s end.
Project co-sponsor Equitrans Midstream Corp. in a Form-8K filing this week with the Securities and Exchange Commission pointed to “unforeseen factors” that have “substantially affected the pace of construction” for the Appalachia-to-Southeast pipeline.
MVP is designed to deliver Marcellus and Utica shale gas to an interconnect with Transco (aka the Transcontinental Gas Pipe Line) at Station 165 in Pittsylvania County, VA.
East Daley analyst Alex Gafford said the firm had predicted delays given MVP’s “incredibly tight timeline” to bring the project into service in 2023.
“We currently forecast MVP to begin service on April 1 and will likely stick with that estimate,” Gafford told NGI. “As a result, in our Northeast Supply and Demand Outlook, we don’t have any trapped gas or rerouting issues in our model.
“Our view is the pipeline will initially fill to only around 400 MMcf/d on April 1 due to downstream constraints” on Transco.
Wood Mackenzie analysts Colette Breshears, Devin Cao and Randall Collum similarly pointed to downstream constraints as a limiting factor on upside to Appalachian outflows when MVP enters service.
“Most of the gas from MVP will fill local Zone 5 demand and push back gas flowing south from eastern Pennsylvania, with only a small portion increasing southbound transport along Transco into Zone 4” and the Gulf Coast, the 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 the pipeline’s designed capacity of around 2 Bcf/d.
“Implied volumes through Station 165 during peak demand averaged roughly 1.5 Bcf/d for the past few years,” the Wood Mackenzie team said. “Using the reported 2.1 Bcf/d design capacity of Station 160 south leaves only around 0.6 Bcf/d for net MVP exports.”
Wood Mackenzie modeling based on a December 2023 MVP start-up would have seen regional production remain flattish or decline slightly over the course of the winter. That forecast is not expected to change significantly with the pipeline now delayed, according to the analysts.
“Nationally, we see the associated gas plays continuing to grow production, with the dry gas plays showing flat to declining production,” they said.
As far as price impacts, the Wood Mackenzie analysts said they would expect a delayed MVP start-up to generally put bullish pressure on Transco Zone 5 and apply bearish pressure farther upstream in Appalachia.
Transco Zone 6 pricing would see “lesser but related” bullish pressure amid higher demand on Zone 5, while Zone 4 would also see bullish pressure given that Zone 5 “depends on increased Zone 4 imports during the height of winter,” the analysts said. “These hubs are chosen as representatives of the connected hubs in each area, but it outlines how we’re considering the impacts of delay.”
Eastern Gas South front month basis skidded lower during the Oct. 11-18 period, falling 2.1 cents to minus-$1.281. Fixed prices for November at the hub tumbled 34.0 cents week/week, a decline of more than 16%, versus a 9.5% week/week discount at Henry Hub, Forward Look data show.
Meanwhile, Transco Zone 5 basis sold off at the front of the curve but strengthened for early 2024. January basis there rose 13.8 cents to end the period at plus-$3.731.
Back Below $3
Nymex futures conceded ground throughout the Oct. 11-18 trading period, including consecutive front month double-digit declines last Friday (Oct. 13) and following the weekend (Oct. 16). November skidded 9.9 cents on Thursday to settle at $2.957.
Earlier in the month, a bullish surprise from the U.S. Energy Information Administration’s (EIA) weekly storage report sent the November contract barreling past the psychological $3 barrier. So it was fitting that a bearish deviation in the latest storage release provided the final impetus to send the front month plummeting back down to sub-$3 territory.
EIA on Thursday reported a 97 Bcf injection for the week ending Oct. 13 that landed well on the upper end of market expectations.
NatGasWeather in a note to clients Thursday pointed to two possible explanations for the plump print from EIA. For one, this could be a make-up for unexpectedly lean builds reported in recent weeks, the firm said.
“The other reason is temperatures were exceptionally comfortable over Texas last week for the first time since last spring, and that led to a massive 40 Bcf build in the South Central EIA region, larger than expected,” NatGasWeather said.
Early season cold over the northern U.S. during the period also likely “didn’t translate to much demand” given lows only reached down into the upper 30s to 40s, the firm added.
The post West Natural Gas Forwards Jittery; MVP Delay Seen Bullish for Transco Zone 5 Pricing appeared first on Natural Gas Intelligence
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