Natural Gas

Today in Energy

Recent Today in Energy analysis of natural gas markets is available on the EIA website.

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price fell 26 cents from $2.23 per million British thermal units (MMBtu) last Wednesday to $1.97/MMBtu yesterday, the lowest price since June 12, 2023.
• Henry Hub futures price: The price of the March 2024 NYMEX contract decreased 13.3 cents, from $2.100/MMBtu last Wednesday to $1.967/MMBtu yesterday. This is the lowest settlement price for the March 2024 contract since trading of this contract began 12 years ago. The price of the 12-month strip, averaging March 2024 through February 2025 futures contracts, declined 12.5 cents to $2.641/MMBtu.
• Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, January 31 to Wednesday, February 7) in line with the decline in the Henry Hub spot price. Price changes ranged from a decrease of $1.01/MMBtu at Algonquin Citygate to an increase of $0.44/MMBtu at Northwest Sumas.
• Natural gas prices in the Northeast decreased from last Wednesday in anticipation of warmer weather moving into the region. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.01 from $3.35/MMBtu last Wednesday to $2.34/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 (Transco Zone 6) trading point for New York City, the price decreased 27 cents from $1.95/MMBtu last Wednesday to $1.68/MMBtu yesterday. During the report week, the Algonquin Citygate price reached a weekly high of $7.10/MMBtu last Friday and Transco Zone 6 reached a weekly high of $2.66/MMBtu on Monday. Natural gas consumption increased because of cooler weather this week and relatively low natural gas prices for this time of year. Temperatures in the Boston Area averaged 35°F, resulting in 210 heating degree days (HDD), 8 more HDDs than last week. Similarly, temperatures in the New York-Central Park Area averaged 39°F, resulting in 178 HDDs, 19 more HDDs than last week. Natural gas consumption in the Northeast increased 9% (2.2 billion cubic feet per day [Bcf/d]), led by a 12% (1.5 Bcf/d) increase in residential and commercial sector consumption, according to data from S&P Global Commodity Insights.
• Prices across the West Coast rose this report week. At Northwest Sumas on the Canada-Washington border, the main natural gas pricing point in the Pacific Northwest, the price rose 44 cents from $2.04/MMBtu last Wednesday to $2.48/MMBtu yesterday. The price at PG&E Citygate in Northern California rose 40 cents, up from $3.14/MMBtu last Wednesday to $3.54/MMBtu yesterday, and in Southern California, the price at SoCal Citygate increased 14 cents from $2.87/MMBtu last Wednesday to $3.01/MMBtu yesterday. Natural gas consumption in the Western region increased 8% (0.8 Bcf/d), led by an 18% (0.7 Bcf/d) increase in residential and commercial sector consumption, according to S&P Global Commodity Insights. Temperatures in the Riverside Area, east of Los Angeles, averaged 52°F, 10°F lower than last week, which resulted in 90 HDDs, 68 more HDDs than last week. In addition, various maintenance events on El Paso Natural Gas Company’s system reduced pipeline capacity on its North Mainline for westbound deliveries of natural gas out of the Permian production region by about 0.2 Bcf/d, or more than 10% of its available capacity, towards the end of the report week.
• Prices across Texas decreased this report week. At the Houston Ship Channel, the price fell 53 cents from $2.01/MMBtu last Wednesday to $1.49/MMBtu yesterday. Natural gas consumption in South Texas decreased 6% (0.5 Bcf/d) driven by an 11% (0.4 Bcf/d) decrease in consumption in the electric power sector. According to our Hourly Electric Grid Monitor, the Electric Reliability Council of Texas (ERCOT) reported electricity generation from natural gas fell to an average of 26% of the total generation mix this report week compared with 51% last week. At the same time, electricity generation from wind increased to an average of 42% of the generation mix this report week compared with 16% last week. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 15 cents this report week, from $1.40/MMBtu last Wednesday to $1.25/MMBtu yesterday, after reaching a weekly low of $0.69/MMBtu last Friday. The Waha Hub traded 72 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 83 cents below the Henry Hub price.

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

• 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 rose 4 cents to a weekly average of $9.46/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands fell 6 cents to a weekly average of $9.07/MMBtu. In the same week last year (week ending February 8, 2023), the prices were $18.30/MMBtu in East Asia and $17.83/MMBtu at TTF. The last time early-February prices at TTF averaged below $10/MMBtu was in 2021.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 8 cents/MMBtu, averaging $7.74/MMBtu for the week ending February 7. Weekly average ethane prices rose 2%, while weekly average natural gas prices at the Houston Ship Channel fell 20%. The ethane premium to natural gas rose 48% week over week. The ethylene spot price rose 2%, increasing the ethylene premium to ethane by 2%. The average weekly propane price rose 5%, while the Brent crude oil price fell 3%. The propane discount relative to crude oil decreased 22% week over week. Normal butane prices remained relatively unchanged, and both isobutane and natural gasoline prices fell 4%, in line with crude oil prices.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 0.8% (0.9 Bcf/d) compared with the previous report week. Dry natural gas production grew by 1.2% (1.2 Bcf/d) to average 104.4 Bcf/d, and average net imports from Canada decreased by 6.5% (0.4 Bcf/d) from last week.
• Demand: Total U.S. consumption of natural gas rose by 1.4% (1.2 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Residential and commercial sector consumption increased by 4.9% (1.7 Bcf/d) week over week. Natural gas consumed for power generation declined by 1.4% (0.5 Bcf/d), and industrial sector consumption was essentially unchanged. Natural gas exports to Mexico decreased 8.9% (0.5 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 13.3 Bcf/d, or 0.7 Bcf/d lower than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals decreased by 4.9% (0.7 Bcf/d) week over week, averaging 13.3 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana decreased by 1.4% (0.1 Bcf/d) to 9.2 Bcf/d, while natural gas deliveries to terminals in South Texas decreased by 15.1% (0.5 Bcf/d) to 2.9 Bcf/d. Nearly all the declines in South Texas occurred at the Corpus Christi LNG terminal, where natural gas receipts fell by, on average, 0.5 Bcf/d, or close to 25% week over week. Natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged at 1.2 Bcf/d.
• Vessels departing U.S. ports: Twenty-four LNG vessels (nine from Sabine Pass; four from Calcasieu Pass; three each from Cameron, Corpus Christi, and Freeport; and two from Cove Point) with a combined LNG-carrying capacity of 89 Bcf departed the United States between February 1 and February 7, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, January 30, the natural gas rig count decreased by 2 rigs from a week ago to 117 rigs, as the Haynesville dropped 2 rigs. The number of oil-directed rigs was unchanged from a week ago at 499 rigs. The Cana Woodford and the Permian added one rig each, and one rig was added among unidentified producing regions. The Eagle Ford dropped two rigs and the Granite Wash dropped one rig. The total rig count, which includes 3 miscellaneous rigs, now stands at 619 rigs, 140 fewer rigs than last year at this time.

Storage

• Net withdrawals from storage totaled 75 Bcf for the week ending February 2, compared with the five-year (2019–2023) average net withdrawals of 193 Bcf and last year's net withdrawals of 208 Bcf during the same week. Working natural gas stocks totaled 2,584 Bcf, which is 248 Bcf (11%) more than the five-year average and 187 Bcf (8%) 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 58 Bcf to 82 Bcf, with a median estimate of 75 Bcf.
• The average rate of withdrawals from storage is 5% lower 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 12.1 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,881 Bcf on March 31, which is 248 Bcf higher than the five-year average of 1,633 Bcf for that time of year.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook