Perplexed by erratic changes in the latest weather models, natural gas traders sent futures lower on Friday. Still, with confidence low and several model runs before the start of a new week, the January Nymex gas futures contract slipped only 3.2 cents to settle at $2.296/MMBtu. February fell 3.8 cents to $2.282.
Spot gas prices, however, were mixed as light national demand was forecast for the next couple of days before another cold shot arrives. Driven by strong gains in the Northeast, the NGI Spot Gas National Avg. climbed 5.0 cents to $2.235.
Just when it appeared weather data had started to converge on prospects for late-December cold, a sudden shift occurred in all the models overnight Thursday. Bespoke Weather Services said all of the runs began to change by Days 4-5 toward more upper-level troughing in the Gulf of Alaska through Western Canada, indicating that something was picked up in the initialization of Thursday night’s runs that was not there at midday.
“As it stands now, the pattern is back easily on the warm side of normal overall, and we still do not see any sign yet of a turn back materially colder, even in the pattern at the end of the 11-15 day,” Bespoke chief meteorologist Brian Lovern said.
The midday Global Forecast System (GFS) model trended further milder through Dec. 23, but was colder for the Dec. 25-28 period, offsetting to keep 15-day run total heating degree days (HDD) little changed compared to Thursday night, according to NatGasWeather. Meanwhile, the afternoon run of the European model trended a little colder for the coming week, but was milder trending for Dec. 20-25 by favoring an exceptionally bearish pattern with much warmer-than-normal conditions over most of the country.
“The end of the European model run at Days 14-15 showed a little stronger cooling pushing back into the northern United States, but still with national demand below normal,” NatGasWeather said. “We thought the European model might have gotten a little too warm last night after it lost a massive 27 HDDs, which proved true by adding 7 HDDs back this run. But it’s still much milder than the data had shown 24 hours ago and is still showing a very bearish set up Dec. 20-26 that’s difficult to ignore.”
Significant shifts were still possible over the weekend, “creating considerable uncertainty regarding where prices will head between now and Monday,” EBW Analytics Group said.
Even with the generally mild outlook for the remainder of the year, blaming weather for weak gas pricing this winter might be the easy thing to do, but is not necessarily accurate as weather has actually been quite supportive, according to Tudor, Pickering, Holt & Co. (TPH).
The U.S. Energy Information Administration (EIA) reported a 73 Bcf withdrawal for the week ending Dec. 6, which was 4% above normal as far as degree days, the firm said. Furthermore, cumulative degree days are 11% above norms so far this withdrawal season, driving cumulative withdrawals 44% above the five-year average.
“That said, a reversion looks to be in store with forecasts showing above-normal temperatures across most of the United States for the next two weeks,” TPH analysts said.
However, liquefied natural gas (LNG) demand is strong on the back of commissioning at the Freeport and Cameron export terminals, adding around 1 Bcf/d and elevating total LNG feed gas demand to around 8 Bcf/d, according to TPH. With demand up about 3 Bcf/d week/week and supply roughly flat, the firm’s preliminary estimate is for a roughly 90 Bcf draw in the next EIA report, versus norms of around 115 Bcf.
Looking further out into 2020, EBW said the market appears to have discounted in-service dates for two new LNG trains that are each expected online by the end of winter. If the second production units at both Freeport and Cameron enter service on schedule, it may provide a modest bullish catalyst for the market.
“By spring, however, uncertain global LNG demand becomes a liability for natural gas futures,” EBW said. “If cargoes face economic shut-ins due to an oversupplied global market, Nymex prices may plunge south of $2.00/MMBtu.”
With a cross-country winter storm set to bring enough snow to shovel and plow along a stretch of 2,000 miles from the Rockies to Maine, spot gas prices were on the rise in some areas of the United States on Friday.
The roots of the storm will produce pockets of snow over the ranges of the interior West, including the Colorado Rockies through Saturday, according to AccuWeather. A foot of fresh snow was forecast for the tops of the slopes in the central and southern Rockies as well as parts of the northern Sierra Nevada.
The storm was forecast to turn eastward and cause snow to break out over the Plains of eastern Colorado, southern Nebraska, much of Kansas and western and central Missouri on Sunday. AccuWeather meteorologist Bernie Rayno said a heavy band of snow could drop six inches to 12 inches across the Central Plains, while cities like Indianapolis could expect snowfall in the three- to six-inch range.
The accumulating snow was forecast to spread rapidly from the middle Mississippi Valley to areas along and just north of the Ohio River in the Midwest into early Monday.
“For parts of the Midwest, central Appalachians and Northeast, this storm will generally bring one-to-six inches with locally higher amounts possible,” AccuWeather senior meteorologist Brett Anderson said.
Later Monday, snow was expected to reach the central Appalachians and was forecast to bend northward toward the lower Great Lakes region as well, according to AccuWeather. “So not only can people in Pittsburgh, Cleveland and Buffalo, New York, expect accumulating snow from the storm, but some snow is in store for Chicago, Detroit and Toronto.”
The storm may begin as snow or sleet in Philadelphia and New York City late Monday, but a fairly quick transition to rain was expected. The same was expected in New England before the storm’s expected departure on Tuesday.
With the chilly air boosting projected demand in the region, cash prices responded accordingly. In the constrained New England region, Algonquin Citygate surged some 74.0 cents to $3.195, while smaller increases were seen in other areas.
In Appalachia, Dominion South rose 7.0 cents to $1.890.
Much of the Southeast and Louisiana continued to decline as the cooler weather was expected to not reach those regions until midweek. In West Texas, El Paso Permian was down 6.0 cents to $1.400 despite stronger prices in downstream markets out West.
Farther south, SoCal Citygate surged 19.0 cents to $4.950 but continues to have increased supply flexibility to meet demand.
For starters, Southern California Gas Co. (SoCalGas) had 74.4 Bcf working gas storage inventories as of Dec. 10, nearly equal to the year-ago level and nearly 10% higher than it was in 2017. Furthermore, rules approved by the California Public Utilities Commission earlier this summer made it easier for SoCalGas to withdraw supplies from its Aliso Canyon storage facility this winter. Before the rule change, the facility was to be called upon only as a last resort.
Repairs to Line 235-2, a critical import line located in southeastern California, were also completed in October, boosting capacity by 270 MMcf/d and increasing access to supplies from the San Juan and Permian basins.
In the country’s midsection, Panhandle Eastern spot gas shot up 33.0 cents to $2.060, while most other pricing hubs in the region saw prices rise by less than half that amount.
On the pipeline front, Enable Gas Transmission plans to begin maintenance Tuesday on the Byars Lake Compressor Station (CS), which would restrict capacity through Amber Junction (Grady County, OK) until Friday. During this time, capacity would be limited to 306 MMcf/d.
“Flows through Amber Junction towards Chandler CS in Latimer County, OK, have averaged 673 MMcf/d over the past 30 days,” Genscape analyst Dominic Eggerman said. “Therefore, 367 MMcf/d of gas will be restricted, which is approximately one-third of the total gas that flows through Chandler and onto the rest of Enable’s system in Arkansas and Louisiana.”
North of the border in Western Canada, NOVA/AECO C cash prices slipped 3.5 cents to average $2.285 despite demand running high in the region.
TPH estimated that intra-Alberta demand was averaging around 6.4 Bcf/d for the week ending Dec. 13, compared to seasonal norms in the 6.0 Bcf/d range.
Natural gas’ share of the Alberta power stack continues to inch its way higher since taking a material step up in 2018 following the retirement of several Alberta coal plants, according to TPH. Year to date, natural gas has accounted for 41.5% of the total power stack, compared to 40% in 2018 and only 30% in 2017, while coal’s share of power generation has shrunk from 59% in 2017 to only 47% today.
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