Natural gas prices for Dec. 9-13 were mostly lower week/week as unseasonably mild weather set up camp across much of the United States. With highs reaching the 70s in Texas and the 60s in parts of the Northeast, the NGI Weekly National Avg. fell 5.5 cents to $2.260.
Boston highs reached the low 60s earlier in the week, leading to dramatic losses at Algonquin Citygate, which averaged the week at $3.405, down 87 cents week/week. Other pricing hubs in New England also posted sharp decreases, while market hubs in other areas of the Northeast were stronger week/week as a midweek cold front boosted demand later in the week.
Genscape Inc. said the chillier weather propelled demand to a projected peak of 108.6 Bcf/d for Wednesday, up from about 86.2 Bcf/d at the start of the week. Pipelines planned accordingly, issuing operational restrictions on systems including ANR Pipeline, Dominion Gas Transmission and Transcontinental Gas Pipe Line Co.
Transco Zone 6-NY averaged $2.550 during the Dec. 9-13 period, gaining 18.5 cents week/week.
Gains were also seen across Appalachia, with most pricing hubs picking up less than 15 cents week/week. However, ongoing maintenance on Texas Eastern Transmission lifted Texas Eastern M-3, Delivery up a whopping 44.5 cents to average $2.135.
There were few other big movers across the country as the majority of prices registered changes of no more than a dime in either direction.
On the West Coast, SoCal Citygate picked up 1.5 cents to average just north of $5.
Another Wild Ride
The midweek cold snap that boosted some markets this week was the latest in series of fronts that have come and gone throughout the winter so far. But with little clarity on whether more sustained cold would arrive later this month, natural gas futures were taken on yet another rollercoaster ride during the Dec. 9-13 period.
When the smoke cleared, the January Nymex futures contract climbed 6.4 cents from Monday to settle at $2.296 on Friday. February rose 4.8 cents to end the week at $2.282.
Erratic swings in the weather data began earlier in December as the American Global Forecast System (GFS) and European models diverged in the amount of projected demand for the latter part of the month. Although they began to align by Dec. 6, another dramatic shift over the Dec. 7-8 weekend left the two weather models at odds to the start the Dec. 9-13 work week.
By Thursday, back-to-back demand gains in the more trustworthy European data provided enough support to lift prices up a solid 8.5 cents at the front of the curve despite a bearish storage report from the U.S. Energy Information Administration (EIA).
The U.S. Energy Information Administration (EIA) reported a 73 Bcf withdrawal from natural gas storage inventories for the week ending Dec. 6, a figure that came in slightly smaller than market expectations. The reported draw also came in a couple ticks below the year-ago withdrawal of 75 Bcf, but it was several Bcf above the 68 Bcf five-year average pull, according to EIA.
Broken down by region, the Midwest posted the largest withdrawal of 27 Bcf, while the East drew down inventories by 24 Bcf, according to EIA. Pacific stocks were down by 10 Bcf, and the Mountain was down by 7 Bcf. The South Central region posted a net withdrawal of 6 Bcf, which included an 11 Bcf draw from nonsalt facilities and a 5 Bcf injection into salts.
Total working gas in storage as of Dec. 6 stood at 3,518 Bcf, 593 Bcf above last year at this time and 14 Bcf below the five-year average, according to EIA.
However, just when it appeared the ball was back in bulls’ court, all weather models moved significantly warmer overnight Thursday. The sudden flip in the data indicated that something may have been picked up in the initialization of Thursday night’s runs that was not there at midday.
The midday Friday GFS model trended further milder through Dec. 23, but was colder trending Dec. 25-28, offsetting to keep 15-day run totaled heating degree days (HDD) little changed versus Thursday’s night’s run, according to NatGasWeather.
“Even though the GFS lost a chunk of demand the past 12 hours, it’s still quite a bit colder compared to the very bearish European model,” the forecaster said. “But it’s hard to believe anything it's showing after numerous busted forecasts the past several weeks.”
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.”
After reaching an intraday high of $2.342 and then plunging to an intraday low of $2.253, the January Nymex futures contract went on to settle near the midpoint of the range.
With weather forecast volatility remaining high, the middle of the coming week could be a turning point, according to Mobius Risk Group. Cold temperatures are forecast to blanket most of the country, and a replication of this pattern when liquidity begins to fade (Christmas holiday) with a “max short” speculative community could be a catalyst for testing recent highs.
“Conversely, a warm theme heading into the annual demand slump of the holidays could be enough to embolden hyper-vigilant speculative bears,” the Houston-based firm said.
Looming Cold Bolsters Cash
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 on Friday for weekend and Monday delivery. In the constrained New England region, Algonquin Citygate surged some 74.0 cents on Friday to average $3.195, while smaller increases were seen in other areas.
In Appalachia, Dominion South rose 7.0 cents for weekend and Monday delivery 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 on Friday 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.