Friday marked another choppy day for natural gas futures, with prices initially fueled by a sharp decline in production but then pressured by weak cash prices and soft demand. The June Nymex gas futures contract ultimately settled at $1.890, down 5.9 cents from Thursday’s close. July slipped 3.6 cents to $2.134.
Spot gas declines were fairly small across much of the country, though steeper decreases were seen on the East Coast despite lingering cool weather in the region. NGI’s Spot Gas National Avg. was down 4.5 cents to $1.520.
Cool weather was seen lingering throughout the first full week of May, but given the time of year, it’s possible the markets prefer to see hotter trends instead of cooler ones, “as they could signal the arrival of early summer heat instead of stalling it,” according to NatGasWeather. The forecaster noted that heating degree days this late in the season “just don’t have the same impact” on demand, and it therefore expects weekly storage builds to remain near or slightly larger than normal.
On Thursday, the Energy Information Administration (EIA) said 70 Bcf was added to storage inventories for the week ending April 24. The injection was on target with several estimates, but some analysts had called for a much higher 80 Bcf build. The injection compared with last year’s 114 Bcf injection for the similar week and the five-year average build of 74 Bcf, and boosted inventories to 2,210 Bcf, according to EIA.
Genscape senior natural gas analyst Eric Fell, who also overshot the injection, said the 70 Bcf appears loose by around 7.5 Bcf/d versus the prior five-year average when compared to degree days and normal seasonality.
“While this week’s report is still very loose versus normal, it was meaningfully tighter than what our models were suggesting and tighter than last week,” Fell said.
The analyst noted that it was the second week in a row in which Genscape missed to the high side. This is most likely because of larger production declines compared to what the firm’s daily pipe scrape models are suggesting.
“This happens when production is changing rapidly in areas where data is obscured by intrastate pipelines,” said Fell. “A large portion of associated and liquids-rich gas production resides behind intrastate systems in Texas, New Mexico, Oklahoma and Colorado. We had the opposite problem last year when oil and liquids rich production was rapidly growing.”
However, it also appears that demand destruction from the coronavirus may have reached a peak, according to Fell. The analyst pointed out that gasoline demand appears to be rebounding and refinery runs increased slightly week/week. Meanwhile, crude stocks grew by 10 million bbl during that time, but the build was smaller than any of the prior four weeks.
“So crude balances have become ”less loose’ as U.S. crude production is clearly falling,” Fell said.
Tudor, Pickering, Holt & Co. analysts said the EIA’s 70 Bcf injection was bullish versus five-year average, but “unless we get material shut-ins in the near future, balances are going to get sloppy.”
TPH data for the current week flow suggested that demand was down around 6.5 Bcf/d week/week on a combination of seasonal weakness and lower liquefied natural gas utilization. On the supply side of the ledger, the firm sees volumes down only 1.0 Bcf/d, with Canadian imports accounting for 0.6 Bcf/d of the drop. This results in a net loosening of 5.5 Bcf/d.
“As a result, we’re expecting a build of around 110 Bcf in the next EIA report, versus norms of 72 Bcf,” TPH analysts said.
Furthermore, without a 2 Bcf/d drop in supply over the next week, it likely sets up a second consecutive triple-digit build, pushing inventories to a more than 21% surplus over the five-year, compared to 18% currently, TPH said.
“Given the importance of shut-ins and implications for pricing, it’s likely to be another volatile week for gas.”
Spot gas prices across the Lower 48 declined Friday as soggy conditions were expected to clear in the coming days on the East Coast, while heat anchored over the Southwest and southern Rockies was set to slowly spread eastward.
NatGasWeather expects light national demand to gradually increase during the week as cooler air sweeps across much of the country, although the forecaster noted the chilly conditions would ease any early season heat over Texas.
“The pattern for May 11-17 favors cool shots continuing across the Midwest and East,” while it is forecast to be warm across the southern United States, “but not hot. The natural gas markets will have to wait for more intimidating heat a little while longer.”
With insignificant demand on the East Coast in the coming days, spot gas markets in the region put up the largest decreases. Algonquin Citygate prices for gas delivered through Monday averaged $1.305, down 21.0 cents day/day.
The seasonal lull in demand lends itself to a slate of pipeline maintenance and from Monday-Friday, Empire Pipeline is set to conduct an outage that is to affect operations across the entire pipe, according to Genscape analyst Josh Garcia.
Specifically, the work simultaneously isolates two segments of the Empire Connector Line to tie in facilities being constructed under the Empire North Project. This results in four separate impact zones on the pipeline, Garcia said.
The more significant of the two segment isolations is the Talisman and Shell gathering systems in Northern, PA, which are to be shut in for the duration of the event. These locations have aggregated a consistent 342 MMcf/d of production over the month of April, although reroutes are possible because of the interconnected nature of the region, according to Garcia.
Another significant isolation cuts off the entire northern line of Empire that runs east to west and comprises the Original Line in the west and the aptly named East Line, which converge southeast of Rochester, NY.
“These meters have aggregated net demand of 219 MMcf/d over the last month,” Garcia said.
Within this segment lie the Chippewa border location with TC Energy Corp.’s Canadian Mainline, three interconnects with National Fuel Gas (NFG) and one with Dominion Transmission, all netting demand over the last 30 days, according to Genscape.
However, with NGI pricing data showing Dawn at a premium over Dominion North and Niagara, which represents NFG’s flows into the TC Energy Mainline, “if these locations don’t shut in, flow economics suggests that the domestic interconnects will flip and serve…Mainline demand,” Garcia said. “In summary, this event will impact operations across the pipe, which will have wider implications to supply and demand within the region.”
Spot gas was less than 10 cents lower day/day across the country’s midsection. Henry Hub slipped 3.5 cents to $1.650 for gas delivered through Monday. Interestingly, Chicago Citygate prices were up 8.5 cents day/day to $1.720 amid some hefty gains on Nicor Gas.
Small losses were seen throughout most of Texas, while the western pricing hubs continued to march higher. El Paso Permian cash was up 15.5 cents to $1.460.
Given lingering chilly weather in Western Canada, NOVA/AECO spot gas slipped only 1.0 cent to C$1.930/GJ.
Even as Old Man Winter refuses to leave without fight, storage inventories continue to refill. Western Canada storage added 12 Bcf for the week ending April 24, the largest build since 2017, according to TPH. The hefty injection is reflective of a functioning storage regime under the TC Energy’s Temporary Service Protocol and soft local demand, analysts said.
TPH data showed that intra-Alberta demand was running about 0.3 Bcf/d below normal seasonal levels, and regional data showed deliveries into the oilsands made up around 0.15 Bcf/d of the delta as shut-ins reduced demand.
“This order of magnitude impact is in line with our expectations and relatively minimal relative to roughly 2.5 Bcf/d of total consumption in the region as operators continue to steam reservoirs despite production being held back,” said the TPH team.
The analysts continue to monitor gas receipts as an indicator of oil shut-ins, but still see only “negligible” impacts so far. Flow data for the final week of April suggested another large build in the coming week, with TPH modeling 13 Bcf verus norms of 6 Bcf.
In Eastern Canada, storage showed a draw of 2 Bcf versus norms of a 4 Bcf build. The late season draw was much needed, according to TPH, as it reduced the surplus to the five-year average from 61% to 48%.
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