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Nat gas weekly

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Market Highlights:

(For the week ending Wednesday, January 31, 2024)

 

Prices

Daily spot prices by region are available on the EIA website.

• Henry Hub spot price: The Henry Hub spot price fell 21 cents from $2.44 per million British thermal units (MMBtu) last Wednesday to $2.23/MMBtu yesterday. 
• Henry Hub futures price: The February 2024 NYMEX contract expired Monday at $2.490/MMBtu, down 15 cents from last Wednesday. The March 2024 NYMEX contract price decreased to $2.100/MMBtu, down 16 cents from last Wednesday to yesterday. The front-month futures contract price has declined after rising above $3.00/MMBtu in the middle of the January. The price of the 12-month strip averaging March 2024 through February 2025 futures contracts declined 14 cents to $2.767/MMBtu. 
• Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, January 24, to Wednesday, January 31) as rising temperatures across much of the nation decreased consumption. Price changes ranged from a decrease of $1.31/MMBtu at Northwest Sumas to an increase of 91 cents at Algonquin Citygate.
  • At the Algonquin Citygate, which serves Boston-area consumers, the price rose 91 cents from $2.44/MMBtu last Wednesday to $3.35/MMBtu yesterday. Prices reached an intraweek high of $8.67/MMBtu on Monday, nearly double the price reported for the prior Friday, the previous trading day. Natural gas consumption in New England fell 17.8% (0.7 billion cubic feet per day [Bcf/d]) this week, led by a 24.2% (0.6 Bcf/d) decrease in residential and commercial sector consumption, according to data from S&P Global Commodity Insights. Average temperatures in the Boston Area were above normal for most of the report week, starting at a high of 46°F last Thursday before falling to 31°F yesterday, resulting in 202 heating degree days(HDDs), 64 fewer HDDs than the previous report week. The Algonquin Gas Transmission pipeline issued an operational flow order (Notice 143337) on Sunday, calling on shippers to ensure “that actual deliveries of gas out of the system must be equal or less than scheduled deliveries.” 
  • In California, the price at PG&E Citygate fell 86 cents from $4.00/MMBtu last Wednesday to $3.14/MMBtu yesterday. Prices also fell at SoCal Citygate in Southern California by 55 cents from $3.42/MMBtu last Wednesday to $2.84/MMBtu yesterday. Natural gas consumption in California fell 4.3% (0.3 Bcf/d) this week, led by a 7.5% (0.2 Bcf/d) decrease in natural gas consumed for power generation, according to data from S&P Global Commodity Insights. In the Riverside Area, inland of Los Angeles, average temperatures rose 5°F from last week to 62°F this report week, leading to 22 HDDs, 33 HDDs fewer than the previous week and 44 HDDs below normal. In the Pacific Northwest, the price at Sumas on the Canada-Washington border fell $1.31 from $3.35/MMBtu last Wednesday to $2.04/MMBtu yesterday. Net flows into the region increased 21% over the past two weeks after a cold snap in mid-January reduced net flows into the region, primarily from Canada and the Desert Southwest, according to data from S&P Global Commodity Insights. In the Seattle City Area, average temperatures rose by 7°F to 52°F this report week, leading to 92 HDDs in the region, 63 HDDs below normal and 49 HDDs less than the previous report week. Natural gas consumption in the Pacific Northwest fell 22% (0.7 Bcf/d) this week, with the residential and commercial sector recording a 34% decrease (0.5 Bcf/d), according to data from S&P Global Commodity Insights.
  • The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 68 cents this report week, from $2.08/MMBtu last Wednesday to $1.40/MMBtu yesterday. The Waha Hub traded 83 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 36 cents below the Henry Hub price. On Monday, the El Paso Natural Gas Company issued a notice of a high linepack condition due to lower natural gas deliveries and higher supply receipts. The notice was canceled on Tuesday. Net outflows from the Permian Basin rose 5% (0.7 Bcf/d) week over week and are up 12% (1.7 Bcf/d) from two weeks ago, according to data from S&P Global Commodity Insights. 
• International futures prices: International natural gas futures price changes were mixed this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia fell 7 cents to a weekly average of $9.42/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased 22 cents to a weekly average of $9.13/MMBtu. In the same week last year (week ending February 1, 2023), the prices were $19.43/MMBtu in East Asia and $18.04/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 13 cents/MMBtu, averaging $7.66/MMBtu for the week ending January 31. Weekly average ethane prices rose 6%, while weekly average natural gas prices at the Houston Ship Channel grew 4%. The ethane premium to natural gas rose 10% week over week. The ethylene spot price rose 1%, decreasing the ethylene premium to ethane by 2%. The average weekly propane price rose 2%, following the Brent crude oil price, which also rose 2%. The propane discount relative to crude oil increased 3% week over week. Normal butane prices fell 4%, isobutane prices fell 3%, and natural gasoline prices rose 4%.

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Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 1.1% (1.2 Bcf/d) compared with the previous report week. Dry natural gas production grew by 3.2% (3.2 Bcf/d) to average 103.1 Bcf/d, and average net imports from Canada decreased by 22.8% (1.8 Bcf/d) from last week. Dry natural gas production remains 2.7 Bcf/d below its pre-winter-storm high of 105.8 Bcf/d that was reported for the week ending December 20. 
• Demand: Total U.S. consumption of natural gas fell by 21.0% (23.9 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Warmer weather was observed across most of the United States, reducing both residential and commercial sector demand and electric power sector demand as space heating consumption fell. Natural gas consumed for power generation declined by 14.0% (5.2 Bcf/d) week over week. In the residential and commercial sectors, consumption declined by 33.2% (16.9 Bcf/d). Industrial sector consumption decreased by 7.0% (1.8 Bcf/d) over this same period. Natural gas exports to Mexico decreased 0.7% (less than 0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 14.0 Bcf/d, or 0.9 Bcf/d higher than last week.

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Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 6.6% (0.9 Bcf/d) week over week, averaging 14.0 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana increased by 1.9% (0.2 Bcf/d) to 9.3 Bcf/d, and natural gas deliveries to terminals in South Texas rose by 10.3% (0.3 Bcf/d) to 3.5 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast rose 41.9% (0.4 Bcf/d) to 1.2 Bcf/d. 
• Vessels departing U.S. ports: Twenty-eight LNG vessels (nine from Sabine Pass; four each from Calcasieu Pass, Cameron, Corpus Christi, and Freeport; two from Elba Island; and one from Cove Point) with a combined LNG-carrying capacity of 103 Bcf departed the United States between January 25 and January 31, according to shipping data provided by Bloomberg Finance, L.P.
• Vessels arriving at U.S. ports: One LNG vessel with a carrying capacity of 3 Bcf docked for off-loading at the Everett LNG terminal in Boston Harbor in Massachusetts between January 25 and January 31, according to shipping data provided by Bloomberg Finance, L.P.
• LNG terminals: Freeport LNG, south of Houston, Texas, reported one of three liquefaction trains will be offline for approximately one month as electrical repairs following the recent winter storm are completed.

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Rig Count

• According to Baker Hughes, for the week ending Tuesday, January 23, the natural gas rig count fell by 1 rig from a week ago to 119 rigs. One rig was dropped among unidentified producing regions. The number of oil-directed rigs increased by 2 rigs from a week ago to 499 rigs. The Cana Woodford and the DJ-Niobrara each added one rig, and the Permian added three rigs; the Eagle Ford dropped one rig, and two rigs were dropped among unidentified producing regions. The total rig count, which includes 3 miscellaneous rigs, now stands at 621 rigs. 

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Storage

• Net withdrawals from storage totaled 197 Bcf for the week ending January 26, compared with the five-year (2019–2023) average net withdrawals of 185 Bcf and last year's net withdrawals of 141 Bcf during the same week. Net withdrawals from storage for the past two weeks combined were 523 Bcf. Working natural gas stocks totaled 2,659 Bcf, which is 130 Bcf (5%) more than the five-year average and 54 Bcf (2%) more than last year at this time. 
• According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net withdrawals of 180 Bcf to 215 Bcf, with a median estimate of 203 Bcf.
• The average rate of withdrawals from storage is 5% higher than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 13.8 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,763 Bcf on March 31, which is 130 Bcf higher than the five-year average of 1,633 Bcf for that time of year.