Ethane production in the United States reached a monthly record of 2.7 million barrels per day (b/d) in April 2023, continuing the upward trend that started in 2013, according to data from our Petroleum Supply Monthly. Increased production in the Permian Basin was the primary driver of the overall increase in ethane production.

From March through May 2023, U.S. average production of ethane exceeded 2.6 million b/d, the highest rate ever. Increased U.S. production of ethane occurred in conjunction with increased production of natural gas. Ethane, along with other natural gas plant liquids (NGPLs), is recovered at natural gas processing plants as raw natural gas from the well is processed to meet natural gas pipeline specifications. Marketed natural gas production, which includes both dry natural gas and NGPLs before they are separated out, also set new records this year. It exceeded 110 billion cubic feet per day (Bcf/d) every month this year through May 2023, the first time such levels were achieved, and averaged 112 Bcf/d from March through May. Natural gas production grew in 2023 after a monthly decline in December 2022 when a winter storm caused both natural gas production and ethane production to decline, especially in Texas and the Midwest.

The Texas Inland and New Mexico refining districts, which include the Permian Basin, accounted for 60% of U.S. ethane production from January through May 2023, slightly higher than the 58% share observed in 2022. Ethane production in these two districts averaged 1.5 million b/d in the first five months of 2023, up 12% (0.2 million b/d) from the same period last year. Ethane production in other refining districts of the United States was essentially unchanged from the same period last year.

U.S. ethane production grew in response to rising demand from both domestic and global consumers. Product supplied of ethane, a proxy for domestic consumption, averaged 2.1 million b/d from January to May 2023 and set a record of 2.2 million b/d in May 2023, up from 2.0 million b/d during May last year. U.S. ethane exports set a record in March 2023, averaging 537,000 b/d. In the first five months of 2023, the United States exported an average of 489,000 b/d, up from 448,000 b/d in January–May 2022. The United States has exported ethane for nearly a decade, and it became the world’s top exporter of ethane in 2015.

In our Short-Term Energy Outlook (STEO), we expect ethane production to average 2.6 million b/d in 2023 and 2024, an increase of 200,000 b/d from 2022 levels. We expect ethane exports to average 480,000 b/d in 2023 and 500,000 b/d in 2024, up from 450,000 b/d in 2022. Domestic ethane consumption is expected to average 2.1 million b/d in 2023 and 2024, up from 2 million b/d in 2022.

Market Highlights:

(For the week ending Wednesday, August 16, 2023)

Prices

  • Henry Hub spot price: The Henry Hub spot price fell 36 cents from $2.91 per million British thermal units (MMBtu) last Wednesday—its highest price since January 2023—to $2.55/MMBtu yesterday, aligning with the decline in the Henry Hub futures price.
  • Henry Hub futures price: The price of the September 2023 NYMEX contract decreased 36.7 cents, from $2.959/MMBtu last Wednesday to $2.592/MMBtu yesterday. The price of the 12-month strip averaging September 2023 through August 2024 futures contracts declined 13.3 cents to $3.340/MMBtu.
  • Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, August 9 to Wednesday, August 16) except in Southern California. Price changes this week ranged from a decrease of $0.42/MMBtu at Sumas on the Canada-Washington border to an increase of $2.85/MMBtu at SoCal Citygate.
    • Price changes in California were mixed this week. The price at PG&E Citygate in Northern California fell 7 cents, down from $5.71/MMBtu last Wednesday to $5.64/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $2.85 from $4.95/MMBtu last Wednesday to $7.80/MMBtu yesterday. El Paso Natural Gas Company reported maintenance on the North Mainline near Leupp, Arizona, beginning on Monday, August 14. In addition, ongoing maintenance is occurring at the SoCalGas pipeline system. Prices in the West remain the highest in the country as above-average temperatures keep demand for cooling high and the Pacific region remains the only region in the United States with below-average storage levels.
    • Prices in the Northeast decreased this week despite an increase in natural gas consumption. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 7 cents from $1.43/MMBtu last Wednesday to $1.36/MMBtu yesterday. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 1 cent from $1.51/MMBtu last Wednesday to $1.50/MMBtu yesterday. Temperatures in the Boston Area increased this week to an average 75°F, leading to 70 cooling degree days (CDD), 11 CDDs above normal, and 11 more than last week. Natural gas consumption in the electric power sector in the Northeast increased 3.0%, or 0.3 billion cubic feet per day (Bcf/d) this week, according to data from S&P Global Commodity Insights. Prices in the Northeast remain the lowest in the country.

    • 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 78 cents to a weekly average of $11.76/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased $1.40 to a weekly average of $11.75/MMBtu. In the same week last year (the week ending August 17, 2022), the prices were $49.94/MMBtu in East Asia and $65.07/MMBtu at TTF.
  • Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 29 cents/MMBtu, averaging $6.95/MMBtu for the week ending August 16. Weekly average ethane prices fell 1%, while natural gas prices at the Houston Ship Channel rose by 5%, narrowing the ethane premium to natural gas by 9% week over week. Both ethylene spot prices and the ethylene to ethane premium remained relatively unchanged. Propane prices fell 9%, while the Brent crude oil price rose 1%, increasing the propane discount relative to crude oil by 12%. The normal butane price fell 5%, the isobutane price fell 1%, and the natural gasoline price remained relatively unchanged.

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 0.2% (0.2 Bcf/d) to an average of 102.0 Bcf/d, and average net imports from Canada increased by 1.8% (0.1 Bcf/d) from last week.
  • Demand: Total U.S. consumption of natural gas rose slightly by 0.3% (0.3 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 0.6% (0.3 Bcf/d) week over week. Industrial sector consumption increased by 0.6% (0.1 Bcf/d), and residential and commercial sector consumption declined by 1.7% (0.1 Bcf/d). Natural gas exports to Mexico decreased 1.5% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.2 Bcf/d, or 0.2 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

  • Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased by 1.4% (0.2 Bcf/d) week over week, averaging 12.2 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Texas increased by 3.0% (0.1 Bcf/d) to 3.9 Bcf/d, while deliveries to terminals in South Louisiana increased by 1.2% (0.1 Bcf/d) to 7.2 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast decreased by 3.4% (less than 0.1 Bcf/d) to 1.1 Bcf/d.
  • Vessels departing U.S. ports: Twenty-four LNG vessels (eight from Sabine Pass; four each from Corpus Christi and Freeport; three each from Cameron and Cove Point; and two from Calcasieu Pass) with a combined LNG-carrying capacity of 89 Bcf departed the United States between August 10 and August 16, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

  • According to Baker Hughes, for the week ending Tuesday, August 8, the natural gas rig count decreased by 5 to 123 rigs. The Eagle Ford added one rig, the Marcellus dropped two rigs, and the Permian dropped four rigs. The number of oil-directed rigs remained constant at 525. The Ardmore Woodford added one rig, and the Permian added two rigs. The Eagle Ford dropped two rigs, and one rig was dropped in unidentified producing regions. The total rig count, which includes 6 miscellaneous rigs, decreased by 5, and it now stands at 654 rigs.

Storage

  • Net injections into storage totaled 35 Bcf for the week ending August 11, compared with the five-year (2018–2022) average net injections of 41 Bcf and last year's net injections of 21 Bcf during the same week. Working natural gas stocks totaled 3,065 Bcf, which is 299 Bcf (11%) more than the five-year average and 549 Bcf (22%) 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 29 Bcf to 43 Bcf, with a median estimate of 36 Bcf.
  • The average rate of injections into storage is the same as 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 10.2 Bcf/d for the remainder of the refill season, the total inventory would be 3,894 Bcf on October 31, which is 299 Bcf higher than the five-year average of 3,595 Bcf for that time of year.