Associated natural gas production increased 9% in 2022 due to higher crude oil production
In 2022, annual production of associated-dissolved natural gas (or associated natural gas) increased 9% to 15.5 billion cubic feet per day (Bcf/d) in the major U.S. onshore crude oil-producing regions (Permian, Bakken, Eagle Ford, Niobrara, and Anadarko) mostly due to an 8% increase in crude oil production. Associated natural gas accounted for more than a third of total natural gas production in these regions and 14% of total U.S. natural gas production. Associated natural gas refers to natural gas that is dissolved in crude oil under the pressure of a geologic formation and is then released when the pressure on the crude oil is relieved by bringing it to the surface. Increasing crude oil production in the Permian region, which spans parts of western Texas and southeastern New Mexico, is driving the growth in associated natural gas production. Currently the largest of the five major U.S. crude oil-producing regions, the Permian region produces more crude oil than the other four regions combined. In 2022, the Permian region increased production of crude oil by 12% and associated natural gas by 15%. Associated natural gas production in the Permian region increased by 1.3 Bcf/d to average 10.2 Bcf/d for the year, and it accounted for 56% of U.S. total associated natural gas production. In recent years, new pipeline takeaway capacity additions are also facilitating associated natural gas production growth. Associated natural gas contains higher ratios of natural gas plant liquids (NGPLs) (such as ethane, propane, normal butane, isobutane, and natural gasoline) than non-associated natural gas. NGPLs are used as fuel for heating and transportation and as feedstocks to produce plastics, resins, and other petrochemicals. Like associated natural gas production, NGPL production has set several consecutive annual record highs, rising to an annual average of 5.9 million barrels per day in 2022. The Texas Inland region, which includes much of the Permian region, accounted for 53% of total U.S. ethane production and 49% of total NGPL production in 2022, up from 51% of ethane production and 46% of NGPL production in 2021, according to our Petroleum Supply Monthly. Information on EIA’s classification of oil and natural gas wells can be found in our Drilling Productivity Report Supplement.
Henry Hub spot price: The Henry Hub spot price fell 28 cents from $3.18 per million British thermal units (MMBtu) last Wednesday to $2.90/MMBtu yesterday. The Henry Hub price remained among the highest of all major U.S. hubs outside of California. Henry Hub futures price: The price of the November 2023 NYMEX contract decreased 32.1 cents, from $3.377/MMBtu last Wednesday to $3.056/MMBtu yesterday. The price of the 12-month strip averaging November 2023 through October 2024 futures contracts declined 15.4 cents to $3.375/MMBtu. Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, October 11 to Wednesday, October 18). Price changes ranged from a decrease of $0.28/MMBtu at the Henry Hub to an increase of $3.42/MMBtu at PG&E Citygate. Prices in California rose this week, as maintenance activities affecting supply from the Permian Basin pushed prices higher. The price at SoCal Citygate in Southern California rose $3.22/MMBtu from $8.48/MMBtu last Wednesday to $11.70/MMBtu yesterday. This price was the highest among major North American hubs for the week. On October 11, the El Paso Natural Gas company declared force majeure on Line 1104 near the Dutch Flats compressor station south of Yucca, Arizona, which carries natural gas into Southern California, reducing operational capacity by approximately 600 million cubic feet per day. The line is expected to return to service on October 20. Supply disruptions caused by maintenance events caused prices to increase, despite more moderate temperatures week over week. Temperatures in the Riverside Area, east of Los Angeles, averaged 74°F this week, 5°F above normal, resulting in 64 cooling degree days (CDD), 19 fewer CDDs than last week and 30 more than normal. Prices at the PG&E Citygate, located in Northern California, rose $3.42/MMBtu from $4.41/MMBtu last week to $7.83/MMBtu on Wednesday. Temperatures in the San Jose Area, located in Northern California, averaged 70°F this week, 5°F above normal, resulting in 37 CDDs, 22 CDDs fewer than last week and 26 more CDDs than normal. Prices in the U.S. Gulf Coast fell this report week as cooler temperatures reduced demand for air conditioning, lowering gas consumption by the electric power sector. Prices at the Houston Ship Channel fell 13 cents from $2.53/MMBtu last Wednesday to $2.40/MMBtu yesterday. Prices at the Henry Hub fell 28 cents from $3.18/MMBtu last Wednesday to $2.90/MMBtu yesterday. Temperatures in the Houston Area averaged 67°F this week, 5°F below normal, resulting in 24 CDDs, 17 fewer CDDs than last week and 30 fewer CDDs than normal. The Houston Area also recorded 8 heating degree days (HDDs) this week, the first HDDs recorded since spring and 5 HDDs above normal. Average weekly temperatures in the Houston area have fallen nearly 16°F from two weeks ago.
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 $2.32 to a weekly average of $16.50/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased $2.49 to a weekly average of $15.78/MMBtu. In the same week last year (week ending October 19, 2022), the prices were $32.11/MMBtu in East Asia and $37.30/MMBtu at TTF. Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 6 cents/MMBtu, averaging $7.21/MMBtu for the week ending October 18. Weekly average ethane prices fell 2%, following weekly average natural gas prices at the Houston Ship Channel, which fell 3% week over week. The ethane premium to natural gas fell 1%. Ethylene spot prices rose 1%, and the ethylene premium to ethane rose 3%. The average weekly propane price rose 2%, following the Brent crude oil price, which rose 3%. The propane discount relative to crude oil rose 4%. The normal butane price rose 2%, the isobutane price rose 4%, and the natural gasoline price rose 1%.
Supply and Demand
Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 1.1% (1.2 Bcf/d) compared with the previous report week. Dry natural gas production grew by 1.3% (1.3 Bcf/d) and averaged 102.6 Bcf/d for the week, the highest weekly average since the week ending May 31 this year. Average net imports from Canada decreased by 1.8% (0.1 Bcf/d) from last week. Demand: Total U.S. consumption of natural gas rose by 2.4% (1.7 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 2.4% (0.8 Bcf/d) week over week. Industrial sector consumption increased by 1.4% (0.3 Bcf/d) and residential and commercial sector consumption increased by 14.8% (2.1 Bcf/d) as cooler temperatures increased heating demand in the Northeast and upper Midwest. Natural gas exports to Mexico decreased 4.7% (0.3 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 14.3 Bcf/d, or 1.5 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 12.2% (1.5 Bcf/d) week over week, averaging 14.3 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana increased by 4.1% (0.4 Bcf/d) to 9.0 Bcf/d, while deliveries to terminals in South Texas increased by 11.4% (0.4 Bcf/d) to 4.2 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast rose 0.8 Bcf/d to 1.1 Bcf/d as the Cove Point LNG terminal in Maryland returned to service after concluding its annual maintenance. Vessels departing U.S. ports: Twenty-nine LNG vessels (10 from Sabine Pass; 5 each from Cameron, Corpus Christi, and Freeport; and 4 from Calcasieu Pass) with a combined LNG-carrying capacity of 108 Bcf departed the United States between October 11 and October 18, according to shipping data provided by Bloomberg Finance, L.P. This week’s LNG vessel count includes five vessels that departed LNG terminals on Wednesday, October 11, but were not included in the vessel count for the previous report week (October 5 through October 11).
Net injections into storage totaled 97 Bcf for the week ending October 13, compared with the five-year (2018–2022) average net injections of 85 Bcf and last year’s net injections of 113 Bcf during the same week. Working natural gas stocks totaled 3,626 Bcf, which is 175 Bcf (5%) more than the five-year average and 300 Bcf (9%) 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 75 Bcf to 102 Bcf, with a median estimate of 84 Bcf. The average rate of injections into storage is 6% 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 8.0 Bcf/d for the remainder of the refill season, the total inventory would be 3,770 Bcf on October 31, which is 175 Bcf higher than the five-year average of 3,595 Bcf for that time of year.