Natural Gas

In the News:

U.S. natural gas-directed rig count has declined 26% since start of 2023

On September 29, the Baker Hughes Company reported 116 active natural gas-directed rigs in the United States, a decrease of 40 rigs from the start of 2023. The decline in active drilling rigs coincides with a decrease in natural gas and crude oil prices for most of 2023, compared with relatively high natural gas and crude oil prices for most of 2022.

Producers typically respond to lower crude oil or natural gas prices by either reducing their development costs or by decreasing their drilling activity by reducing the number of active drilling rigs deployed. Increases in development costs such as drilling materials and labor in the last two years have encouraged producers to reduce their drilling activities to cut costs. Reduced drilling activity typically lags price decreases by four to six months because it takes time for producers to respond to price changes. The extent to which producers respond to price changes is based on several factors, such as uncertainty around future prices, volatility in the market, and price hedging.

In 2022, the natural gas spot price at the U.S. benchmark Henry Hub averaged $6.45 per million British thermal units (MMBtu). The Henry Hub price began to decline in January of this year and averaged $2.46/MMBtu in the first nine months of 2023, almost $4.00/MMBtu less than the 2022 annual average.

The natural gas-directed rig count fluctuated between 150 rigs and 162 rigs for the first four months of 2023 and then began to decline in May, falling to a low of 113 rigs on September 8.

In the Permian region, which accounted for 18% of all U.S. natural gas production in 2022, most natural gas production is associated with crude oil production. As a result, producers in the Permian region typically respond to changes in the crude oil price when planning their exploration and production activities.

After averaging over $100.00 per barrel (b) from March through July 2022, the West Texas Intermediate (WTI) crude oil price began to decline in August 2022. The price then averaged below $80.00/b from January through July 2023 but began to rise in August 2023 due to Saudi Arabia’s crude oil production cuts. Despite the recent WTI price increase, the oil-directed rig count in the Permian region dropped from 357 rigs in May to 308 rigs on September 29.

Although both the natural gas- and oil-directed rig counts have generally declined throughout 2023, average daily U.S. production of natural gas and crude oil in 2023 has been higher than in 2022. U.S. dry natural gas production averaged 103.0 billion cubic feet per day (Bcf/d) in the first seven months of 2023, up 3% from the 2022 annual average of 99.6 Bcf/d, according to our Natural Gas Monthly. U.S. crude oil production averaged 12.7 million barrels per day (b/d) in the first seven months of 2023, up 7% (0.8 b/d) from 2022. Increased well-level productivity in the Permian region has contributed to greater production efficiency.

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price rose 20 cents from $2.71 per million British thermal units (MMBtu) last Wednesday to $2.91/MMBtu yesterday.
• Henry Hub futures price: The October 2023 NYMEX contract expired last Wednesday at $2.764/MMBtu. The November 2023 NYMEX contract price increased to $2.962/MMBtu, up 6 cents from last Wednesday to yesterday. The price of the 12-month strip averaging November 2023 through October 2024 futures contracts rose 4 cents to $3.260/MMBtu.
• Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, September 27, to Wednesday, October 4). Price changes ranged from a decrease of $0.23/MMBtu at Northwest Sumas on the Canada-Washington border to an increase of $4.06/MMBtu at SoCal Citygate.
• Prices increased in California amid supply disruptions. The price at SoCal Citygate in Southern California increased $4.06 from $2.98/MMBtu last Wednesday to $7.04/MMBtu yesterday. Natural gas supplies in California decreased 8.2% (0.6 billion cubic feet per day [Bcf/d]) this week, according to data from S&P Global Commodity Insights. Natural gas flows from the Desert Southwest into Southern California fell 8.3% (0.3 Bcf/d) as production in the New Mexico portion of the Permian Basin decreased 6.3% (0.4 Bcf/d) week over week. El Paso Natural Gas Company reported ongoing maintenance this week on its system, which delivers natural gas from the Permian production region to Southern California. The price at PG&E Citygate in Northern California rose $1.61, up from $3.25/MMBtu last Wednesday to $4.86/MMBtu yesterday. Maintenance on the Williams-operated Northwest Pipeline, which delivers natural gas from Canada and the Rocky Mountains to the Western United States, has reduced natural gas flows south by approximately 0.2 Bcf/d since September 26. In addition, maintenance on the Gas Transmission Northwest pipeline, operated by TC Energy, has reduced natural gas deliveries from Canada into the Pacific Northwest and the Malin, Oregon, delivery point which supplies the PG&E service territory.
• At Northwest Sumas on the Canada-Washington border, which connects to the Gas Transmission Northwest pipeline, the price fell 23 cents from $2.24/MMBtu last Wednesday to $2.01/MMBtu yesterday. Natural gas consumption in the electric power sector in the Pacific Northwest decreased 6.1% (0.1 Bcf/d) this week, according to data from S&P Global Commodity Insights. Puget Sound Energy reported the share of natural gas used for electricity generation declined by 6.9% this report week and the share of electricity generated by renewable sources (wind, solar, and hydro) increased 6.4%, according to our Hourly Electric Grid Monitor.
• Prices in major Northeast markets remained the lowest in the country, and price changes were mixed this week. At Algonquin Citygate, which serves Boston-area consumers, the price decreased 2 cents from $1.51/MMBtu last Wednesday to $1.49/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price rose 5 cents from $1.28/MMBtu last Wednesday to $1.33/MMBtu yesterday. Natural gas consumption in the electric power sector in New York and New Jersey increased 23% (0.4 Bcf/d), according to data from S&P Global. From Monday to Wednesday, temperatures in the New York-Central Park Area averaged 72°F, 9°F above normal, resulting in 21 cooling degree days (CDD), 16 CDDs more than normal. Since September 15, Tennessee Gas Pipeline (TGP) has been repairing compressor station 315 in Wellsboro, Pennsylvania, reducing pipeline capacity by about 0.2 Bcf/d for westbound natural gas deliveries. TGP reports an estimated return to service date of October 13.
• In the Midwest, the Chicago Citygate price increased 33 cents from $2.27/MMBtu last Wednesday to $2.60/MMBtu yesterday. Natural gas deliveries from the Appalachian production region decreased 11% (0.7 Bcf/d) this week, according to data from S&P Global Commodities, and total supplies declined 4% (0.5 Bcf/d) week over week (see discussion on TGP above).

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

• International futures prices: International natural gas futures prices 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 increased 20 cents to a weekly average of $14.44/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased 50 cents to a weekly average of $12.11/MMBtu. In the same week last year (week ending October 5, 2022), the prices were $37.99/MMBtu in East Asia and $51.00/MMBtu at TTF. Stocks of natural gas in storage in the European Union reached 96.3% of capacity on Tuesday, compared with 89.7% on the same day last year.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 1 cent/MMBtu, averaging $7.44/MMBtu for the week ending October 4. Weekly average ethane prices rose 3%, following weekly average natural gas prices at the Houston Ship Channel, which rose 4% week over week. The ethane premium to natural gas remained relatively unchanged. Ethylene spot prices rose 1%, and the ethylene premium to ethane remained relatively unchanged. The average weekly propane price rose 1%, while the Brent crude oil price remained relatively unchanged. The propane discount relative to crude oil fell 1%. The normal butane price fell 2%, the isobutane price rose 3%, and natural gasoline price fell 4%.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas remained the same as in the previous report week, averaging 106.0 Bcf/d. Dry natural gas production decreased by 0.4% (0.4 Bcf/d) to an average 100.9 Bcf/d, and average net imports from Canada increased by 6.8% (0.3 Bcf/d) from last week.
• Demand: Total U.S. consumption of natural gas fell by 0.9% (0.6 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation declined by 2.3% (0.9 Bcf/d) week over week. Industrial sector consumption increased by 0.3% (0.1 Bcf/d), and residential and commercial sector consumption increased by 2.1% (0.2 Bcf/d). Natural gas exports to Mexico were essentially unchanged, and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.5 Bcf/d, or 0.6 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 5.0% (0.6 Bcf/d) week over week, averaging 12.5 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana increased by 5.0% (0.4 Bcf/d) to 8.2 Bcf/d, while deliveries to terminals in South Texas increased by 5.9% (0.2 Bcf/d) to 4.0 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged at 0.3 Bcf/d. The Cove Point LNG terminal in Maryland continues to be offline because of annual maintenance.
• Vessels departing U.S. ports: Twenty-one LNG vessels (seven from Sabine Pass; four each from Corpus Christi and Freeport; three from Cameron; two from Calcasieu Pass; and one from Elba Island) with a combined LNG-carrying capacity of 79 Bcf departed the United States between September 28 and October 4, according to shipping data provided by Bloomberg Finance, L.P.
• LNG terminals: On September 30, Freeport LNG Development, L.P. requested approval from the Federal Energy Regulatory Commission (FERC) to continue work to return the Freeport LNG export facility to full commercial operations. This request includes activities to move into Phase 2 operations, which would return the second loading dock to service.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, September 26, the natural gas rig count decreased by 2 from a week ago to 116 rigs. The Permian added one rig while the Marcellus dropped one rig, and two rigs were dropped among unidentified producing regions. The number of oil-directed rigs decreased by 5 from a week ago to 502 rigs. The Mississippian and Williston each added one rig, the Granite Wash dropped one rig, and the Permian dropped six rigs. The total rig count, which includes 5 miscellaneous rigs, stands at 623 rigs, 142 fewer than last year at this time.

Storage

• Net injections into storage totaled 86 Bcf for the week ending September 29, compared with the five-year (2018–2022) average net injections of 103 Bcf and last year's net injections of 126 Bcf during the same week. Working natural gas stocks totaled 3,445 Bcf, which is 172 Bcf (5%) more than the five-year average and 357 Bcf (12%) 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 injections of 87 Bcf to 98 Bcf, with a median estimate of 94 Bcf.
• The average rate of injections into storage is 7% lower than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 10.0 Bcf/d for the remainder of the refill season, the total inventory would be 3,767 Bcf on October 31, which is 172 Bcf higher than the five-year average of 3,595 Bcf for that time of year.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook