Weather Forecasts Impacts U.S. Gas Futures

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Covid-19 Fears Combine with Warmer Weather Forecasts to Send Natural Gas Futures Below $1.70

Natural Gas Futures Extend Rebound as Covid-19 Creates Bearish Headwinds

Covid-19 Expected to Hit Demand, Supply as Natural Gas Futures Steady

Natural Gas Futures Called Lower as Markets Weigh Covid-19 Impacts

After being driven sharply lower by an increasingly mild weather forecast, natural gas futures sustained even more damage on Friday as global fears of the coronavirus continued to hammer stocks and energy commodities. The April Nymex gas futures contract plunged to an intraday low of $1.642/MMBtu before going on to settle at $1.684, down 6.8 cents from Thursday’s close. May also fell 6.8 cents to land at $1.732.

Spot gas, which traded Friday for delivery on Sunday and Monday, also moved lower as any remnants of the blustery conditions that hit the United States in the final days of February were set to dissipate. NGI’s Spot Gas National Avg. dropped 10.5 cents to $1.525.

The latest weather data, already fairly warm, trended further milder overnight Thursday as the American model lost more than 10 heating degree days (HDD) and the already warmer European model lost three to four more HDD, according to NatGasWeather. The midday Global Forecast System continued to trim demand from its outlook, losing another four HDD, the firm said.

However, while the warmer weather trends undoubtedly aided Friday’s selling, the move lower also was likely influenced by major moves in commodity and equity markets because of the coronavirus fears, according to NatGasWeather. Stocks continued to plunge on Friday, and energy commodities went along for the ride. West Texas Intermediate front month futures dropped below $44/bbl early Friday before recovering a bit, while Brent crude broke below $50.

The global markets were poised to extend the worst losing streak since the 2008 financial crisis, with the virus, officially dubbed Covid-19, forecast to pound productivity levels this year.

“Our current assessment forecasts that Covid-19 could result in global E&P investments falling by around $30 billion in 2020 — a significant hit to the industry,“ said Rystad Energy’s Audun Martinsen, head of oilfield service research. Some of the investments are likely to come back in 2021, he said, but the situation is expected to worsen in March, slamming the global services industry well beyond Asia.

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Federal Reserve Chair Jerome Powell attempted to suppress concerns about the outbreak’s impact on the homefront. In a statement Friday, Powell said, “The fundamentals of the U.S. economy remain strong. However, the coronavirus poses evolving risks to economic activity. The Federal Reserve is closely monitoring developments and their implications for the economic outlook. We will use our tools and act as appropriate to support the economy.”

As for domestic gas prices, continued downside could lie ahead as weather models point to March 12 for better prospects of late season cold, but with much more evidence needed to expect it, according to NatGasWeather. “It’s quite possible the weather data trended too mild and adds demand back over the weekend, but it would need to be a considerable amount to be bullish.”

Eyes On Storage

With the withdrawal season rapidly drawing to a close, the effect of the shift is to “nearly guarantee” that end-of-season storage may be well above 1,900 Bcf, according to EBW Analytics Group. The Energy Information Administration’s (EIA) most recent storage report showed that only 143 Bcf was drawn out of storage for the week ending Feb. 21. That compares with a 167 Bcf draw for the similar week last year and a five-year average withdrawal of 122 Bcf, according to EIA.

Total working gas in storage as of Feb. 21 stood at 2,200 Bcf, 637 Bcf above year-ago levels and 179 Bcf above the five-year average, EIA said.

After a string of tight EIA stats, the 143 Bcf draw reflects a market that appears loose/bearish by about 1 Bcf/d versus the five-year average when compared to degree days and normal seasonality, according to Genscape Inc. It is impossible to reconcile the reported 143 Bcf number versus the previous week’s 152 Bcf draw given around 10 Bcf of added demand week/week driven by colder weather and relatively flat net supply, the firm said.

Senior natural gas analyst Eric Fell said the previous week’s EIA storage report was 13 Bcf larger than Genscape’s projection. “Taken at face value,” the latest numbers relative to the previous week “would imply that weather-adjusted balances suddenly shifted by nearly 4 Bcf week/week absent any big changes in production, weather, etc.”

As such, it appears the last two storage reports look like EIA inventory “true-ups,” with the prior week’s reported withdrawal being overstated, which led to the most recent withdrawal being understated (the true-up), according to Fell and analyst Nicole McMurrer.

With 1.9 Tcf end-March storage now back in the realm of possibility, market bears will have the reins until sequential production declines are “not a matter of when, but a matter of how much,” according to Mobius Risk Group. In addition to Apache Corp., which bowed out of the Alpine High development in West Texas because of low natural gas and natural gas liquids prices, Continental Resources Inc. indicated it is trimming its near-term guidance for spending and production on what it views as a “fundamentally oversupplied” market with “demand even further impacted by the coronavirus.”

Other producers also have pledged to reduce spending and drilling activity. Comstock Resources Inc. planned 17% reduction in capital spend and a 29% decrease in the number of wells connected, and EQT Corp., the Appalachian “behemoth,” is expecting growth of less than 10%, “which is meaningful considering the base from which they will grow,” Mobius said.

Permian Pain

With another round of losses across the Lower 48, already weak Permian Basin markets suffered another blow.

Waha spot gas slipped 3.0 cents to average 19.0 cents, but some transactions sank below zero in Friday trading for gas delivered on Sunday and Monday.

Genscape analysts see prolonged weakness in the Permian market as one potential relief valve for stranded volumes has been delayed, with Carso Infraestructura y Construcción announcing it would not bring its Samalayuca-Sasabe project online until September.

“We had been modelling Samalayuca-Sasabe would begin operations in May,” Genscape senior natural gas analyst Rick Margolin said. “This announcement prolongs about 0.25 Bcf/d of relief for the Permian.”

Samalayuca-Sasabe is a project in northern Mexico that would parallel the El Paso Natural Gas (EPNG) South Mainline. According to Genscape, it would provide “an alternative, cheaper, more direct route” for Permian molecules to flow to northwestern Mexican markets — gas currently moves that direction through New Mexico and Arizona on EPNG.

“Though the project is not expected to create an incremental increase in U.S. exports to Mexico, it helps debottleneck the Permian by clearing space on El Paso that can be backfilled by Permian gas to flow to U.S. Southwest and Southern California markets instead,” Margolin said.

As for California, spot gas prices came crashing down Friday despite a planned pipeline maintenance that would restrict imports. With chilly weather subsiding ahead of the scheduled work, SoCal Citygate tumbled 22.5 cents to $1.895; slightly smaller losses were seen farther north.

Southern California Gas (SoCalGas) is scheduled to begin work on Monday in the Blythe Sub-Zone, consisting of the SoCalGas Blythe and Ehrenberg receipt points, which would cut firm operating capacity by 190 MMcf/d, to 800 MMcf/d from around 990 MMcf/d.

“These points have averaged a receipt of about 885 MMcf/d in the past 30 days,” Genscape analyst Joseph Bernardi said. Meanwhile, SoCalGas is conducting an in-line inspection on its Line 2001 that is scheduled to last through March 8.

In the Rockies, Ruby-Receipts cash dropped 16.0 cents day/day to average $1.480, while prices at Panhandle Eastern in the Midcontinent fell 14.5 cents to $1.265.

The Midwest posted losses of less than a dime across the region, while benchmark Henry Hub slipped 5.5 cents to $1.725.

On the East Coast, steep sell-offs continued as much milder weather was in store to start the new week. Tenn Zone 6 200L spot gas plunged 35.5 cents to $1.925. Transco Zone 6 non-NY was down only 10.5 cents to $1.645.

How Weather Forecasts Are Affecting US Natural Gas Futures

Natural gas prices

December natural gas (BOIL) (FCG) futures contracts fell 0.29% to $3.04 per MMBtu (or million British thermal units) in electronic exchange at 2:04 AM EST on October 27, 2020. In contrast, December E-Mini S&P 500 (SPY) futures contracts rose 0.05% to 2,563 in electronic exchange at 2:04 AM.

US natural gas futures are near a four-week low. They are also down 5% and 9% in the last three and 12 months. Changes in natural gas prices impact gas producers (IXC) (IYE) like Newfield Exploration (NFX), Cabot Oil & Gas (COG), and WPX Energy (WPX).

Weather forecasts

The US National Weather Service forecasts that temperatures will be warmer than average across most parts of the US this winter. The last two winters have been the warmest on record. The temperatures in December, January, and February are expected to be warmer than average temperatures, which could lead to less heating demand, which affects natural gas demand and in turn prices.

March 2020 natural gas (UNG) (UGAZ) futures closed at $3.13 per MMBtu on October 26, 2020. April 2020 natural gas futures closed at $2.95 per MMBtu on the same day. The spread between March 2020 and April 2020 natural gas futures was the lowest in more than five years on October 26, 2020, due to warm winter forecasts.

However, in early October 2020, the NOAA (or National Oceanic and Atmospheric Administration) predicted that temperatures this winter would be 13% colder than the last winter across the US. As a result, US natural gas (DGAZ) (GASL) futures had risen 3.5% to $2.98 per MMBtu on October 12, 2020. Changes in natural gas prices impact gas producers (VDE) (XOP) like Newfield Exploration and WPX Energy.

Changes in weather influence demand, inventories, and natural gas prices.

U.S. natgas futures fall over 4% on less cold weather forecasts for December

(Reuters) – U.S. natural gas futures fell over 4% to a near two-month low on Monday on forecasts for less cold weather and heating demand through late December than previously expected.

Meteorologists now forecast the weather over the U.S. Lower 48 states will fluctuate from warmer to colder than normal through Dec. 20 before turning warmer than normal from Dec. 21 through at least Dec. 24. Previously, they predicted temperatures would return to near-normal levels after remaining lower than normal from Dec. 11-Dec. 19.

“Despite a near-term shot of cold that will boost heating demand in the Midwest and East in the middle of this week, weather forecasts haven’t held on to any sustained colder-than-normal period so far in December,” Daniel Myers, market analyst at Gelber & Associates in Houston, said in a report, noting near record production has helped ease “any concern that the market will run short in coming months.”

Front-month gas futures for January delivery on the New York Mercantile Exchange (NYMEX) fell 10.2 cents, or 4.4%, to settle at $2.232 per million British thermal units, their lowest close since Oct. 11.

Earlier in the session, the front-month fell to $2.158, its lowest since Aug. 23.

That price collapse caused futures for February to trade at a premium over January for the first time since 2008.

It also caused the premium of futures for March over April 2020, a spread traders use to bet on winter weather, and futures for all of 2020 to drop to their lowest levels on record.

Those price declines prompted speculators to boost their net short positions on the NYMEX and Intercontinental Exchange last week by 44,641 contracts to 213,682, their highest since August, according to data from the U.S. Commodity Futures Trading Commission (CFTC).

With less cold weather forecast, data provider Refinitiv cut its projections for average demand for next week in the Lower 48 states, including exports, to 123.4 billion cubic feet per day (bcfd) from 131.2 bcfd on Friday. Refinitiv also reduced its forecast for average demand this week to 118.0 bcfd from 119.7 bcfd on Friday.

Gas flows to liquefied natural gas (LNG) export plants rose to a record 8.2 bcfd on Sunday with an increase in flows to the second train at Freeport LNG’s plant in Texas, up from 7.9 bcfd on Saturday, according to Refinitiv data. That compares with an average of 7.6 bcfd last week.

Separately, traders said Kinder Morgan Inc’s Elba Island LNG export plant in Georgia could send out its first cargo this week.

Pipeline flows to Mexico, meanwhile, slipped to four-month low of 4.9 bcfd on Sunday from 5.1 bcfd on Saturday, according to Refinitiv data. That compares with an average of 5.3 bcfd last week and an all-time daily high of 6.2 bcfd on Sept. 18.

Analysts said utilities likely pulled 82 billion cubic feet (bcf) of gas from storage during the week ended Dec. 6. That compares with a withdrawal of 75 bcf during the same week last year and a five-year (2020-18) average decline of 68 bcf. [EIA/GAS]

If correct, the decrease would cut stockpiles to 3.509 trillion cubic feet (tcf), 0.7% below the five-year average of 3.532 tcf for this time of year.

Analysts said stocks would likely return to a surplus over the five-year average during the next month or so as rising production enables utilities to leave more gas in storage.

Gas production in the Lower 48 states slipped to 95.3 bcfd on Sunday from 95.5 bcfd on Saturday, according to Refinitiv. That compares with an average of 95.4 bcfd last week and a record high of 96.3 bcfd on Nov. 30.

Week ended Week ended Year ago Five-year

Dec. 6 Nov. Dec. 6 average

(Forecast) 29(Actual) Dec. 6

U.S. natgas storage (bcf): -82 -19 -75 -68

Refinitiv Heating (HDD), Cooling (CDD) and Total (TDD) Degree Days

Two-Week Total Forecast Current Day Prior Day Prior Year 10-Year 30-Year Norm

U.S. GFS HDDs 403 430 376 419 423

U.S. GFS CDDs 4 3 1 3 3

U.S. GFS TDDs 407 433 377 422 426

Refinitiv U.S. Weekly GFS Supply and Demand Forecasts

Prior Week Current Next Week This week Five-Year

Week last year Average For

U.S. Lower 48 Dry Production 95.6 95.4 95.6 87.3 76.4

U.S. Imports from Canada 7.8 8.1 8.4 8.9 8.5

U.S. LNG Imports 0.0 0.0 0.0 0.3 0.3

Total U.S. Supply 103.5 103.6 104.0 96.5 85.2

U.S. Exports to Canada 3.6 3.8 3.7 3.4 2.5

U.S. Exports to Mexico 5.3 5.3 5.3 4.9 3.6

U.S. LNG Exports 7.5 8.2 8.3 4.5 1.6

U.S. Commercial 15.0 15.4 16.7 15.9 14.1

U.S. Residential 24.9 25.2 28.3 27.2 23.8

U.S. Power Plant 26.9 27.8 28.1 25.4 23.4

U.S. Industrial 24.4 24.8 25.3 25.0 23.4

U.S. Plant Fuel 4.7 4.7 4.7 4.7 4.7

U.S. Pipe Distribution 2.6 2.7 2.8 2.7 2.7

U.S. Vehicle Fuel 0.1 0.1 0.1 0.1 0.1

Total U.S. Consumption 98.7 100.8 106.0 101.0 92.2

Total U.S. Demand 115.2 118.0 123.4 113.8 99.9

SNL U.S. Natural Gas Next-Day Prices ($ per mmBtu)

Hub Current Day Prior Day

Henry Hub 2.31 2.42

Transco Z6 New York 2.16 2.66

PG&E Citygate 3.31 3.29

Dominion South 1.72 1.86

Chicago Citygate 2.16 2.20

Algonquin Citygate 3.94 4.50

SoCal Citygate 4.28 5.25

Waha Hub 1.35 1.46

SNL U.S. Power Next-Day Prices ($ per megawatt-hour)

Hub Current Day Prior Day

New England 39.50 41.50

PJM West 22.25 23.50

Ercot North 22.75 24.00

Mid C 28.75 29.38

Palo Verde 22.00 26.67

Reporting by Scott DiSavino; editing by Jonathan Oatis

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