Lower natural gas production and stronger export demand may keep bulls in the driver’s seat in the weeks and months ahead, but Mother Nature refused to sit back and not have her say. A warmer turn in the latest weather forecasts pushed the November Nymex futures contract back below the coveted $3.00/MMBtu mark on Friday, shedding 3.6 cents to $2.971. December dropped 7.7 cents to $3.195.
Spot gas prices were mostly lower Friday, but colder weather moving into the East lifted prices in the region. NGI’s Spot Gas National Avg. climbed 2.5 cents to $2.490.
Given Thursday’s supportive storage data and increasing export demand, it was interesting to see how weather would factor into current market dynamics. There have been hints of warmer weather creeping up in earlier models, and on Friday, both the American and European datasets trimmed demand from the back of the 11- to 15-day outlook.
Bespoke Weather Services said the models moved toward strong upper-level ridging anchored over the Midwest, suggesting that risks to the current forecast still were to the warmer side after the first couple of days of November. There also was the possibility of a “strongly warm, very low demand pattern” setting up east of the Rockies in the Nov. 5-15 time frame.
The forecaster said the market still has the coming week’s cold to deal with, especially in the Rockies to Midwest, “but this has been a constant in the forecast for awhile now, so should be factored into market sentiment solidly at this point.”
Feed gas deliveries to U.S. liquefied natural gas (LNG) terminals on Friday held above 8 Bcf, but they were down about 0.75 Bcf from midweek. Production, meanwhile, was slightly lower in the early data but is expected to be revised higher as it typically is.
Global Hike ‘Not Justified’
On the LNG front, the retreat in feed gas flows may only be temporary. With LNG traffic able to resume transit in the waterway near the Sabine Pass terminal and vessels able to access the Cameron facility, exports were projected to quickly take off in the coming weeks.
Nevertheless, the constraints in U.S. exports that have been simmering for the past couple of months have resulted in tighter global balances and helped send gas prices higher in Asia and Europe. Energy Aspects analysts said the Japan Korea Marker (JKM) December-February strip appeared to be edging up toward pricing in European reloads, but they said attracting U.S. deliveries should be enough for the Northeast Asian market to balance.
“This snapback of LNG supply should serve to bring down near-curve JKM prices early next month,” the Energy Aspects team said.
There are other constraints in the global market, however. The second production unit at the 15.6 million metric ton/year Gorgon liquefaction plant in Australia was expected to remain offline until at least Nov. 5. The train has been offline since May when welding cracks were discovered in the propane heat exchangers. Sponsor Chevron Corp. may need to take Train 1 down for inspection.
“This effectively adds a month to the supply cut at Gorgon this winter, meaning an additional six cargoes lost from the Pacific basin balance,” said Energy Aspects.
The firm’s analysts said the length of time required to fix welding faults with the propane heat exchangers at Train 2 means there is a “substantial risk” of lengthy outages at the other two liquefaction trains should faults be discovered there as well. However, they see “low risk” of faults being discovered at Train 1 since the unit was examined last year. It’s been longer since Train 3’s last inspection, though, and Energy Aspects expects one to take place in January.
“If faults are discovered, supply from that train could be cut for around five and a half months, similar to the length of time that train two will have been offline by early November,” the firm said.
Adding to the supply crunch, Royal Dutch Shell plc’s Prelude floating LNG facility also in Australia is expected to be offline at least through the rest of this year.
Meanwhile, global demand is “proving surprisingly strong,” according to Energy Aspects, particularly in Korea and China. The firm, however, views most of the spot demand as “precautionary,” given forecasts for a cold winter, which would leave little demand for spot cargoes in late winter if heating degree days (HDD) are in line with long-term averages.
Therefore, analysts don’t “think the recent highs of JKM mid-winter 2020-21 prices are justified.”
Analysts at Tudor, Pickering, Holt & Co. (TPH) similarly took issue with the rise in European Title Transfer Facility (TTF) prices. Although storage withdrawals have already kicked in after ending the injection season slightly below year-ago levels, the recent price hike is incentivizing incremental Russian flows, which recently reached 16.8 Bcf/d. This was the highest level so far this year and above TPH’s modeled expectations of 16.3 Bcf/d.
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“With withdrawal season officially underway, weather will now be the crucial variable,” said the TPH team.
Under a normal weather scenario, the analysts see inventories exiting around 50% above the five-year average. “In our view, it’s going to take a very strong winter to support 2Q2021/3Q2021 TTF pricing of $4.75/MMBtu, and we maintain our bearish view on the European market, relative to strip pricing.”
Tight U.S. Balances
Analysts were more constructive on the U.S. price trajectory as storage data has consistently pointed to tightening supply/demand balances.
On Thursday, the Energy Information Administration (EIA) said Lower 48 stocks climbed by 49 Bcf for the week ending Oct. 16. This lifted inventories to 3,926 Bcf, which is 345 Bcf more than year-ago levels and 327 Bcf above the five-year average.
The EIA figure was the latest in a string of datasets illustrating “remarkable” weather-adjusted tightness, according to Mobius Risk Group. As NGI previously noted, Mobius said the overall injection and the 6 Bcf draw from salt facilities in the South Central region showed a “material reduction in the year/year storage surplus on both accounts.”
These two data points, coupled with the prior four weeks’ tallies, showed how quickly the market can tighten when production is declining and LNG exports are rebounding, as well as the potential issues if November ends up warmer than normal, according to Mobius. The current seasonal forecast for November is 27 population-weighted HDDs warmer than normal and almost 100 less than November 2019.
“At present, the market is looking for a build in the 30s next Thursday and pivoting on weather alone; this would imply that the final week of the traditional injection season may post a single digit build,” Mobius said. “For reference, there has not been a single-digit build for the final week of October in the shale era.”
Noting that winter strip pricing has come under pressure in recent days, the firm said it was unknown how much sidelined production could be delivered into this period. EQT Corp., the largest domestic gas producer, has returned all previously curtailed volumes to sales.
“How much more the broader Appalachian complex and Haynesville producers can push out from November-March will undoubtedly have some effect on market prices,” said Mobius. “But unless these two regions can muster a decidedly larger increase than market expectations, we could be on our way toward exploring what a global gas market looks like when multiple regions are competing for supply.”
Though spot gas prices across the country were generally lower, Permian Basin markets suffered the biggest blow Friday.
Some cooler temperatures moving into the region over the weekend sapped a bit of weather demand. However, the main driver of Thursday’s massive 78.5-cent decline, a force majeure on El Paso Natural Gas (EPNG), was lifted Friday.
Nevertheless, Waha dropped another 92.0 cents to average minus 82.0 cents for gas delivery through Monday.
Meanwhile, Genscape Inc. said Permian production has remained suppressed, averaging around 9.8 Bcf/d in the last week-plus. For comparison, it had been running above 11 Bcf/d as recently as the end of August.
Other Texas markets also moved into the red Friday. Houston Ship Channel fell 16.5 cents to $2.835.
In the Midcontinent, prices were mixed. Most of the declines seen in the region were limited to a nickel, while gains along the Northern Natural Gas Pipeline were upward of 20.0 cents. Northern Natural Demarc averaged $3.215 for the three-day gas delivery.
The majority of hubs in Louisiana fell around 5 cents or so, as did those in the Southeast. The exception, once again, was Dominion Energy Cove Point, which jumped 32.5 cents day/day to $1.305.
Meanwhile, Dominion Energy Transmission Inc. (DETI) on Thursday said it would restrict deliveries to Columbia Gas Transmission (TCO) at the Cornwell, WV, interconnect to a level of 98 MMcf/d. This was because of TCO’s inability to receive gas from DETI at the interconnect.
DETI normally reports operational capacity of zero at the interconnect, according to Genscape, but it has a design capacity of 200 MMcf/d. For the 14 days prior to the outage, flows had averaged 143 MMcf/d and maxed at 197 MMcf/d.
“At the time of writing, scheduled capacity has fallen to 58 MMcf/d, a drop of 104 MMcf/d over two days,” said Genscape analyst Josh Garcia, who added that there is no estimated return to service.
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