Natural Gas

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price increased 1 cent from $2.76 per million British thermal units (MMBtu) last Wednesday to $2.77/MMBtu yesterday.
• Henry Hub futures price: The price of the October 2023 NYMEX contract increased 5.3 cents, from $2.680/MMBtu last Wednesday to $2.733/MMBtu yesterday. The price of the 12-month strip averaging October 2023 through September 2024 futures contracts declined 6 cents to $3.180/MMBtu.
• Select regional spot prices: Natural gas spot prices fell at most major trading hubs this report week (Wednesday, September 13 to Wednesday, September 20). Price changes this week ranged from a decrease of 83 cents/MMBtu at PG&E Citygate to an increase of 11 cents/MMBtu at the Houston Ship Channel.
• California’s natural gas spot prices decreased more than other locations but remained the highest in the country. The price at SoCal Citygate in Southern California fell 74 cents from $4.87/MMBtu last Wednesday to $4.13/MMBtu yesterday. The price at PG&E Citygate in Northern California fell 83 cents from $4.37/MMBtu last Wednesday to $3.54/MMBtu yesterday. Total consumption of natural gas in California fell 11% (0.6 billion cubic feet per day [Bcf/d]) week over week, led by a decrease of 26% (0.6 Bcf/d) in consumption by the electric power sector, according to data from S&P Global Commodity Insights (SPGCI). Average temperatures in the Riverside Area, inland from Los Angeles, fell 10°F this week to 70°F, resulting in 68 fewer cooling degree days (CDD) compared with last week and 41 CDDs fewer than normal levels, leading to lower demand for air conditioning.
• Prices in the Northeast decreased this week as cooler weather contributed to lower natural gas consumption. At the Algonquin Citygate, which serves Boston-area consumers, the price fell 38 cents from $1.74/MMBtu last Wednesday to $1.36/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 61 cents from $1.69/MMBtu last Wednesday to $1.08/MMBtu yesterday. In the Boston Area, the average temperature was 67°F, a decrease of 8°F from the previous week, leading to 15 CDDs compared with 71 CDDs last week. Temperatures in the New York Central Park Area followed a similar pattern as the Boston Area. Natural gas consumption in the electric power sector in the Northeast decreased by 22% (2.5 Bcf/d) week over week, according to data from SPGCI.
• Prices at the Waha hub in West Texas, which is located near Permian Basin production activities, fell week over week as operational issues on pipelines in the region restricted natural gas takeaway capacity. The Waha price fell to an intraweek low of $1.68/MMBtu on Monday before closing the week at $1.76/MMBtu on Wednesday, down 44 cents from last Wednesday. Yesterday's price represented a discount of over $1.00/MMBtu to the Henry Hub price. The Permian Highway Pipeline, which transports natural gas from the Permian production region to the Gulf Coast, declared force majeure on Friday after an operational incident required a temporary service stoppage. The pipeline was brought back to full service on Tuesday. The El Paso Natural Gas Company also declared force majeure at the Roswell, Lordsburg, and Caprock compressor stations, restricting natural gas flows west out of the Permian producing region. The company declared a second force majeure at the Roswell station on Wednesday after lifting the previous force majeure on Monday.

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

• International futures prices: International natural gas futures prices increased 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 47 cents to a weekly average of $13.83/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased 31 cents to a weekly average of $11.29/MMBtu. In the same week last year (week ending September 21, 2022), the prices were $43.97/MMBtu in East Asia and $56.63/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 1 cent/MMBtu, averaging $7.88/MMBtu for the week ending September 20. Weekly average ethane prices remained relatively unchanged, while natural gas prices at the Houston Ship Channel rose 5% week over week, narrowing the ethane premium to natural gas by 5%. Ethylene spot prices rose 4%, widening the ethylene premium to ethane by 7%. The average weekly propane price fell 1%, while the Brent crude oil price rose 3%. The propane discount relative to crude oil rose 9%. The normal butane price remained relatively unchanged, the isobutane price rose 2%, and the natural gasoline price increased 2%.

Supply and Demand

• Supply: According to data from SPGCI, the average total supply of natural gas fell by 1.4% (1.5 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.8% (0.8 Bcf/d), driven mostly by a 0.6 Bcf/d decrease in supply from the Permian Basin. Average net imports from Canada decreased by 12.7% (0.7 Bcf/d) from last week.
• Demand: Total U.S. consumption of natural gas fell by 6.7% (4.8 Bcf/d) compared with the previous report week, according to data from SPGCI. Natural gas consumed for power generation declined by 12.7% (5.3 Bcf/d) week over week, driven by falling temperatures across much of the United States. Industrial sector consumption increased by 0.8% (0.2 Bcf/d) week over week, and residential and commercial sector consumption increased by 3.8% (0.3 Bcf/d). Natural gas exports to Mexico decreased 1.3% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 13.0 Bcf/d, or 0.9 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals rose by 7.5% (0.9 Bcf/d) week over week, averaging 13.0 Bcf/d, according to data from SPGCI. Natural gas deliveries to terminals in South Texas rose by 33.9% (1.0 Bcf/d) to 4.0 Bcf/d. Pipeline nominations to the Freeport LNG facility, located south of Houston, fell to a weekly low of 0.3 Bcf/d on September 13 before returning to 1.9 Bcf/d on September 20, similar to levels seen earlier in the month. Nautral gas deliveries to terminals in South Louisiana were essentially unchanged. Natural gas deliveries to terminals outside the Gulf Coast decreased by 9.1% (0.1 Bcf/d) to 0.9 Bcf/d. The Cove Point LNG liquefaction terminal began annual maintenance on Wednesday, September 20.
• Vessels departing U.S. ports: Twenty-eight LNG vessels (eight from Sabine Pass; five from Freeport; four each from Cameron and Corpus Christi; three from Cove Point; and two each from Calcasieu Pass and Elba Island) with a combined LNG-carrying capacity of 101 Bcf departed the United States between September 14 and September 20, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, September 12, the natural gas rig count increased by 8 to 121 rigs. The Eagle Ford added three rigs and five rigs were added among unspecified producing regions. The number of oil-directed rigs rose by 2 to 515 rigs. The Eagle Ford dropped three rigs, the Permian and Granite Wash added two rigs each, and the Williston added one rig. The total rig count, which includes 5 miscellaneous rigs, increased by 9 and now stands at 641 rigs.

Storage

• Net injections into storage totaled 64 Bcf for the week ending September 15, compared with the five-year (2018–2022) average net injections of 84 Bcf and last year's net injections of 99 Bcf during the same week. Working natural gas stocks totaled 3,269 Bcf, which is 183 Bcf (6%) more than the five-year average and 410 Bcf (14%) 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 55 Bcf to 77 Bcf, with a median estimate of 65 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 11.1 Bcf/d for the remainder of the refill season, the total inventory would be 3,778 Bcf on October 31, which is 183 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