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 rose 63 cents from $2.60 per million British thermal units (MMBtu) last Wednesday to $3.23/MMBtu yesterday, the second day in a row Henry Hub was above $3.20/MMBtu. The last time the Henry Hub price was at $3.00/MMBtu or above for more than one day was in early November 2023.
• Henry Hub futures price: The price of the February 2024 NYMEX contract increased 37.1 cents, from $2.668/MMBtu last Wednesday to $3.039/MMBtu yesterday. The price of the 12-month strip averaging February 2024 through January 2025 futures contracts climbed 14.2 cents to $3.008/MMBtu, with higher prices next winter pulling up the 12-month average. The January 2025 futures contract rose above $4.00/MMBtu on January 9, significantly higher than futures prices for all other months in the strip.
• Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, January 3 to Wednesday, January 10). Price changes ranged from a decrease of $2.82/MMBtu at Algonquin Citygate to an increase of $2.99/MMBtu at Northwest Sumas.
• Prices in the Northeast decreased this report week despite an increase in natural gas consumption. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $2.82 from $6.86/MMBtu last Wednesday to $4.04/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased $1.08 from $4.00/ MMBtu last Wednesday to $2.92/MMBtu yesterday. Prices declined early in the report week but have risen since Monday in response to decreasing temperatures and increased demand for space heating. Temperatures in the Boston Area averaged 34°F this week, resulting in 214 heating degree days (HDD), 27 more HDDs than last week. Temperatures in the New York-Central Park Area averaged 39°F, resulting in 176 HDDs, 24 more HDDs than last week. Natural gas consumption in the Northeast increased 10% (2.5 billion cubic feet per day [Bcf/d]), according to data from S&P Global Commodity Insights, driven by a 14% (1.8 Bcf/d) increase in residential and commercial sector consumption.
• The price at Northwest Sumas on the Canada-Washington border and the main natural gas pricing point in the Pacific Northwest rose $2.99 from $3.47/MMBtu last Wednesday to $6.46/MMBtu yesterday. Temperatures in the Seattle City Area averaged 42°F this week, resulting in 159 HDDs, 33 more HDDs than last week. Natural gas consumption in the Pacific Northwest increased 9% (0.2 Bcf/d), according to S&P Global Commodity Insights. In advance of colder weather moving into the region, Gas Transmission Northwest, which receives natural gas from Canada at Kingsgate in Idaho, issued a cold weather notice and operational flow order advising shippers to keep natural gas receipts and deliveries in balance to ensure system integrity. Westcoast Energy Inc., which delivers natural gas to the Huntingdon Delivery Area in British Columbia, Canada, issued pipeline curtailment notices most of this report week. Rising prices across the Pacific Northwest increased the price at Malin, Oregon, the main delivery point into the PG&E service territory, rising by $2.98 from $3.62/MMBtu last Wednesday to $6.60/MMBtu yesterday.
• In California, the price at PG&E Citygate in Northern California rose $2.87, up from $4.11/MMBtu last Wednesday to $6.98/MMBtu yesterday, following price increases in the Pacific Northwest. Prices also increased at SoCal Citygate in Southern California by $2.71 from $3.91/MMBtu last Wednesday to $6.62/MMBtu yesterday. Natural gas consumption in California rose 7% (0.4 Bcf/d), driven by a 15% (0.3 Bcf/d) increase in residential and commercial consumption. Net natural gas flows into California from the Desert Southwest decreased 12% (0.5 Bcf/d), contributing to the increase in prices at SoCal Citygate. Various maintenance events on El Paso Natural Gas Company’s pipeline system reduced pipeline capacity for delivery of natural gas westbound out of the Permian production region.

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

• International futures prices: International natural gas futures prices decreased 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 12 cents to a weekly average of $11.44/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased 3 cents to a weekly average of $10.35/MMBtu. In the same week last year (week ending January 11, 2023), the prices were $27.67/MMBtu in East Asia and $22.02/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 23 cents/MMBtu, averaging $6.98/MMBtu for the week ending January 10. Weekly average ethane prices rose 20%, while weekly average natural gas prices at the Houston Ship Channel fell 11%. The ethane premium to natural gas rose 130% week over week. The ethylene spot price rose 2%, decreasing the ethylene premium to ethane by 8%. The average weekly propane price rose 1%, while the Brent crude oil price remained relatively unchanged. The propane discount relative to crude oil decreased 1% week over week. Normal butane prices fell 5%, isobutane prices fell 2%, and natural gasoline prices rose 2%.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas fell by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.8% (0.9 Bcf/d) to average 104.2 Bcf/d, and average net imports from Canada increased by 12.1% (0.7 Bcf/d) from last week.
• Demand: Total U.S. consumption of natural gas rose by 4.3% (4.3 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Residential and commercial sector consumption increased by 8.4% (3.3 Bcf/d) week over week, driven by lower temperatures nationwide. Natural gas consumed for power generation rose by 2.1% (0.7 Bcf/d), and industrial sector consumption increased by 1.0% (0.3 Bcf/d). Natural gas exports to Mexico increased 9.7% (0.5 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 14.7 Bcf/d, or 0.1 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 1.0% (0.1 Bcf/d) week over week, averaging 14.7 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana decreased by 1.0% (0.1 Bcf/d) to 9.2 Bcf/d. Natural gas deliveries to terminals in South Texas increased by 5.4% (0.2 Bcf/d) to 4.4 Bcf/d, and natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged.
• Vessels departing U.S. ports: Twenty-eight LNG vessels (eight from Sabine Pass; four each from Calcasieu Pass, Corpus Christi, and Freeport; three each from Cameron and Elba Island; and two from Cove Point) with a combined LNG-carrying capacity of 100 Bcf departed the United States between January 4 and January 10, 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 4 and January 10, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, January 2, the natural gas rig count decreased by 2 rigs from a week ago to 118 rigs. The Eagle Ford added one rig, the Haynesville and the Permian each dropped one rig, and one rig was dropped among unidentified producing regions. The number of oil-directed rigs increased by 1 rig from a week ago to 501 rigs. The Permian added three rigs, the Mississippian added one rig, the Eagle Ford dropped one rig, and two rigs were dropped among unidentified producing regions. The total rig count, which includes 2 miscellaneous rigs, stands at 621 rigs, down 20% from last year’s peak of 775 rigs reported on January 13, 2023.

Storage

• Net withdrawals from storage totaled 140 Bcf for the week ending January 5, compared with the five-year (2019–2023) average net withdrawals of 89 Bcf and last year's net withdrawals of 23 Bcf during the same week. Working natural gas stocks totaled 3,336 Bcf, which is 348 Bcf (12%) more than the five-year average and 436 Bcf (15%) 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 111 Bcf to 147 Bcf, with a median estimate of 123 Bcf.
• The average rate of withdrawals from storage is 28% 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 15.8 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,981 Bcf on March 31, which is 348 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