Natural Gas

In the News:

U.S. monthly dry natural gas production reaches record high in November 2023

U.S. dry natural gas production in the Lower 48 states (L48) reached an all-time monthly high of 104.9 billion cubic feet per day (Bcf/d) in November of 2023, according to S&P Global Commodity Insights. L48 dry natural gas production this year (through November 2023) is up 3.3% (3.3 Bcf/d) from the 2022 annual average. After averaging 101.5 Bcf/d for the first eight months of 2023, L48 dry natural gas production increased 3.2 Bcf/d from September to November 2023.

About 97% of the increase (3.1 Bcf/d) in U.S. dry natural gas production since September occurred in three regions. Production in the Appalachia region, the largest natural gas producing region in the United States, increased by an average of 1.5 Bcf/d from September to November, helped by the expansion of natural gas transportation capacity from the Marcellus shale in Pennsylvania and West Virginia. Continued increases in crude oil and associated natural gas production in the Permian region—the second-largest natural gas producing region in the United States—resulted in a 1.0 Bcf/d increase in natural gas production from September to November. Production in the Anadarko region in Oklahoma rose from recent summer lows, increasing by 0.6 Bcf/d in the same months.

Despite this most recent increase in L48 dry natural gas production, the rate of production growth in the first 11 months of 2023 was lower than in 2022. The annual growth rate in dry natural gas production was 5.3% (4.9 Bcf/d) in 2022, compared with 3.3% (3.3 Bcf/d) for the first 11 months of 2023, according to data from S&P Global Commodity Insights.

In our December 2023 Short-Term Energy Outlook, we forecast total U.S. dry natural gas production will continue to increase in 2024, up 1.2% compared with 2023.

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price fell 40 cents from $2.73 per million British thermal units (MMBtu) last Wednesday to $2.33/MMBtu yesterday.
• Henry Hub futures price: The price of the January 2024 NYMEX contract decreased 23.4 cents, from $2.569/MMBtu last Wednesday to $2.335/MMBtu yesterday. The price of the 12-month strip averaging January 2024 through December 2024 futures contracts declined 18.3 cents to $2.563/MMBtu.
• Select regional spot prices: Natural gas spot prices fell at most locations this week (Wednesday, December 6, to Wednesday, December 13), mostly in line with the U.S. benchmark Henry Hub price. Price changes ranged from a decrease of $6.41/MMBtu at Algonquin Citygate to an increase of $1.23/MMBtu at the Waha Hub.
• Prices in the Northeast decreased this week because of above-average temperatures and below-average heating degree days (HDDs). At the Algonquin Citygate, which serves Boston-area consumers, the price went down $6.41 from $9.80/MMBtu last Wednesday to $3.39/MMBtu yesterday. The Algonquin Citygate price reached a weekly low of $2.38/MMBtu on Friday in advance of warmer weather moving into the region over the weekend. Temperatures in the Boston Area averaged 41°F this week, the same as last week, which resulted in 167 HDDs, also the same as last week, and 27 HDDs fewer than normal. In addition, the unit at the Millstone nuclear power station in Waterford, Connecticut, that had been offline since October 20 was operating at close to full capacity by the end of this report week. Natural gas consumption in the electric power sector in New England declined 11% (0.1 billion cubic feet per day [Bcf/d]), according to data from S&P Global Commodity Insights.
• Across the West Coast, prices decreased this week. The price at PG&E Citygate in Northern California fell 65 cents, down from $4.86/MMBtu last Wednesday to $4.21/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased 6 cents from $4.37/MMBtu last Wednesday to $4.31/MMBtu yesterday. Temperatures in the Riverside Area, east of Los Angeles, averaged 58°F this week, resulting in 47 HDDs, 25 HDDs fewer than normal. The price at Northwest Sumas on the Canada-Washington border, the main natural gas pricing point in the Pacific Northwest, fell $2.46 from $3.58/MMBtu last Wednesday to $1.12/MMBtu yesterday. Temperatures in the Seattle City Area averaged 43°F, resulting in 149 HDDs, 12 HDDs fewer than normal. In addition, natural gas storage inventories in the Pacific region totaled 289 billion cubic feet for the week ending December 8, which is 41% more than year-ago levels.
• West Texas was among the few markets in North America where prices increased this report week. The price at the Waha Hub, which is located near Permian Basin production activities, rose $1.23 this report week, from $0.64/MMBtu last Wednesday to $1.87/MMBtu yesterday. The Waha Hub traded 46 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded $2.09 below the Henry Hub price. Natural gas production in the Permian region decreased 1% (0.1 Bcf/d) this week and flows of natural gas westbound out of the Permian region increased 4% (0.1 Bcf/d), according to data from S&P Global Commodity Insights. Various maintenance events on the El Paso Natural Gas system concluded this week, resulting in increased pipeline capacity for natural gas flowing out of the region. In addition, since September, intrastate pipeline takeaway capacity in West Texas has increased by 1.1 Bcf/d with the completion of the Permian Highway Pipeline expansion (0.6 Bcf/d) and the Whistler Pipeline expansion (0.5 Bcf/d).

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 decreased 33 cents to a weekly average of $15.77/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased $1.18 to a weekly average of $11.73/MMBtu. In the same week last year (week ending December 14, 2022), the prices were $33.46/MMBtu in East Asia and $42.46/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 26 cents/MMBtu, averaging $6.66/MMBtu for the week ending December 13. Weekly average ethane prices fell 10%, while weekly average natural gas prices at the Houston Ship Channel fell 16%. The ethane premium to natural gas rose 13% week over week. The ethylene spot price fell 4%, decreasing the ethylene premium to ethane by 2%. The average weekly propane price fell 4%, while the Brent crude oil price fell 5%. The propane discount relative to crude oil decreased 6% on the week. Normal butane prices rose 7%, isobutane prices fell 6%, and natural gasoline prices fell 4%.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas fell by 0.2% (0.3 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.2% (0.2 Bcf/d) to a weekly average of 105.2 Bcf/d, and average net imports from Canada decreased by 8.8% (0.5 Bcf/d) from last week. Dry natural gas production has averaged 105.0 Bcf/d since the start of November.
• Demand: Total U.S. consumption of natural gas rose by 4.4% (4.0 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation rose by 3.0% (1.0 Bcf/d) week over week. Industrial sector consumption increased by 1.2% (0.3 Bcf/d) and residential and commercial sector consumption increased by 8.2% (2.7 Bcf/d). Natural gas exports to Mexico decreased 3.2% (0.2 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 14.6 Bcf/d, or 0.5 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 3.9% (0.5 Bcf/d) week over week, averaging 14.6 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana increased by 7.5% (0.6 Bcf/d) to 9.2 Bcf/d. Natural gas deliveries to terminals in South Texas decreased by 2.4% (0.1 Bcf/d) to 4.2 Bcf/d, and natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged at 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 Cove Point; and one from Elba Island) with a combined LNG-carrying capacity of 105 Bcf departed the United States between December 7 and December 13, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, December 5, the natural gas rig count increased by 3 rigs from a week ago to 119 rigs as the Haynesville added 3 rigs. The number of oil-directed rigs decreased by 2 rigs from a week ago to 503 rigs. The Ardmore Woodford and Cana Woodford each added one rig, the Eagle Ford added two rigs, the Permian dropped one rig, and five rigs were dropped among unidentified producing regions. The total rig count, which includes 4 miscellaneous rigs, stands at 626 rigs, 154 fewer rigs than last year at this time.

Storage

• Net withdrawals from storage totaled 55 Bcf for the week ending December 8, compared with the five-year (2018–2022) average net withdrawals of 81 Bcf and last year's net withdrawals of 46 Bcf during the same week. Working natural gas stocks totaled 3,664 Bcf, which is 260 Bcf (8%) more than the five-year average and 245 Bcf (7%) 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 46 Bcf to 63 Bcf, with a median estimate of 55 Bcf.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook