Natural Gas

In the News:

Associated natural gas production nearly triples in the top three Permian oil plays since 2018

Associated-dissolved natural gas (associated natural gas) produced from the three top producing tight oil plays in the Permian region—the Wolfcamp, Spraberry, and Bone Spring plays—has nearly tripled since 2018, from an annual average of 4.7 billion cubic feet per day (Bcf/d) to 13.7 Bcf/d in the first seven months of 2023. Production has grown due to both rising crude oil production in the Permian region and an increasing gas-to-oil ratio (GOR) among the oil wells in these three plays. The GOR measures the volume of natural gas per barrel of oil that a well produces.

The Permian region, which spans parts of western Texas and southeastern New Mexico, is the top crude-oil producing region in the United States, accounting for more than 40% of total U.S. crude oil production; it is the second-largest natural-gas-producing region in the country, accounting for about a quarter of total U.S. marketed natural gas production. Most of the natural gas produced in the Permian region is associated natural gas. Increased crude oil production has contributed to increased associated natural gas production in the Permian region. In the Spraberry, Wolfcamp, and Bone Spring plays, average annual crude oil production has more than tripled since 2018, from 1.3 million barrels per day (b/d) to 4.1 million b/d in 2022.

The Spraberry, Wolfcamp, and Bone Spring plays produce a majority of the associated natural gas within the Permian region. Over the past decade, the combined GOR of these three plays has increased from 2.0 thousand cubic feet of natural gas per barrel of oil produced (Mcf/b) in 2013 to 3.1 Mcf/b in the first seven months of 2023. From 2013 to 2023, associated natural gas production from these three plays increased by 13.2 Bcf/d; about 4.7 Bcf/d of the increase came as a result of the increased GOR compared with 2013, while the other 8.5 Bcf/d of increased production came from increased crude oil production.

We define oil wells as those with a GOR of less than or equal to 6.0 Mcf/b. Any increase in the GOR in an oil well means more natural gas per barrel of oil is being produced.

The GOR of an oil well increases naturally over time. Pressure within the reservoir declines progressively as more oil is brought to the surface, which allows more natural gas to be released from the geologic formation. As more oil and natural gas is released within a well, the GOR tends to progressively increase, increasing the volume of associated natural gas produced per every barrel of oil.

We provide a national breakdown of crude oil and natural gas production volumes based on well type classification annually.

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price rose 33 cents from $2.86 per million British thermal units (MMBtu) last Wednesday to $3.19/MMBtu yesterday.
• Henry Hub futures price: The November 2023 NYMEX contract expired Friday at $3.164/MMBtu, up 15 cents from last Wednesday. The December 2023 NYMEX contract price increased to $3.494/MMBtu, up 12 cents from last Wednesday to yesterday. The price of the 12-month strip averaging December 2023 through November 2024 futures contracts climbed 12 cents to $3.505/MMBtu.
• Select regional spot prices: Natural gas spot prices rose at most locations this week (Wednesday, October 25, to Wednesday, November 1). Price changes ranged from a decrease of $1.84/MMBtu at PG&E Citygate to an increase of $2.02/MMBtu at SoCal Citygate.
• Prices across the Northeast rose this week but remain among the lowest in North America. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $1.61 from $1.28/MMBtu last Wednesday to $2.89/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 97 cents from $1.21/MMBtu last Wednesday to $2.18/MMBtu yesterday. Natural gas consumption in the Northeast increased 9% (1.5 billion cubic feet per day [Bcf/d]), according to data from S&P Global Commodity Insights. Consumption in the electric power sector rose 9% (0.7 Bcf/d) to meet air-conditioning demand early in the report week, while residential and commercial sector consumption rose 14% (0.8 bcf/d) to meet heating demand later in the week. Temperatures in the New York-Central Park Area were warmer than normal early in the report week and averaged 72°F on October 28, resulting in 7 cooling degree days (CDDs) when there are normally close to 0 CDDs this time of year. Temperatures proceeded to decline throughout the week and averaged 44°F on November 1, resulting in 21 heating degree days (HDDs), 8 HDDs more than normal.
• In the Midwest, the Chicago Citygate price increased 68 cents from $2.05/MMBtu last Wednesday to $2.73/MMBtu yesterday and reached a weekly high of $3.45/MMBtu on Monday, the highest price since January 12, as colder weather moved into the region. Natural gas consumption in the residential and commercial sector increased more than 100% (3.7 Bcf/d) to 7.1 Bcf/d this week, according to data from S&P Global Insights, to meet increased demand for heating. Temperatures in the Chicago Area averaged 46°F this week, resulting in 134 HDDs, 86 HDDs more than last week and 20 HDDs more than normal. Temperatures averaged a weekly low of 34°F on Tuesday, 14°F below normal.
• Price changes on the West Coast were mixed this week, but prices there remain among the highest in North America. The price at Northwest Sumas on the Canada-Washington border fell $1.59 from $6.04/MMBtu last Wednesday to $4.45/MMBtu yesterday. The price at PG&E Citygate in Northern California fell $1.84, down from $7.93/MMBtu last Wednesday to $6.09/MMBtu yesterday, while the price at the SoCal Citygate in Southern California increased $2.02 from $5.31/MMBtu last Wednesday to $7.33/MMBtu yesterday. Net flows of natural gas into the Pacific Northwest increased 12% (0.5 Bcf/d) this week, and increased flows from the Rocky Mountains and Desert Southwest more than offset a decline in natural gas imports from Canada, according to data from S&P Global Commodity Insights. Southern California Gas Company (SoCal Gas) reported maintenance on its pipeline system this week resulting in capacity reductions of 0.5 Bcf/d to 1.0 Bcf/d in both the southern and northern regions.

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 39 cents to a weekly average of $17.82/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased 29 cents to a weekly average of $15.36/MMBtu. In the same week last year (week ending November 2, 2022), the prices were $28.97/MMBtu in East Asia and $33.96/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 11 cents/MMBtu, averaging $6.97/MMBtu for the week ending November 1. Weekly average ethane prices fell 3%, while weekly average natural gas prices at the Houston Ship Channel rose 26% week over week. The ethane premium to natural gas fell 39%. Ethylene spot prices remained relatively unchanged, and the ethylene premium to ethane rose 1%. The average weekly propane price fell 2%, while the Brent crude oil price fell 3%. The propane discount relative to crude oil fell 4%. The normal butane price rose 2%, the isobutane price rose 6%, and the 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 fell by 0.2% (0.2 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.5% (0.5 Bcf/d) to a weekly average of 102.4 Bcf/d, and average net imports from Canada increased by 5.3% (0.3 Bcf/d) from last week.
• Demand: Total U.S. consumption of natural gas rose by 16.1% (11.3 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Residential and commercial sector consumption increased by 61.8% (9.2 Bcf/d) as cooler weather moved into the Midwest and Northeast, the largest consuming regions of natural gas for space heating. Natural gas consumed for power generation rose by 3.5% (1.1 Bcf/d) week over week, and industrial sector consumption increased by 4.4% (1.0 Bcf/d). Natural gas exports to Mexico decreased 2.7% (0.2 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 13.9 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 rose by 2.0% (0.2 Bcf/d) week over week, averaging 13.9 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana increased by 2.9% (0.2 Bcf/d) to 8.7 Bcf/d. Natural gas deliveries to terminals in South Texas and outside the Gulf Coast were essentially unchanged, averaging 4.1 Bcf/d in South Texas and 1.1 Bcf/d outside the Gulf Coast.
• Vessels departing U.S. ports: Twenty-nine LNG vessels (nine from Sabine Pass; five each from Cameron and Corpus Christi; four from Freeport; three from Calcasieu Pass; two from Elba Island; and one from Cove Point) with a combined LNG-carrying capacity of 108 Bcf departed the United States between October 26 and November 1, according to shipping data provided by Bloomberg Finance, L.P.
• LNG terminals: On October 27, Freeport LNG Development, L.P., received approval from the Federal Energy Regulatory Commission (FERC) to begin commissioning facilities needed to return to service the second loading dock at the Freeport LNG export terminal. Additional authorization to restart operations is necessary to reinstate service for Loop 2 LNG circulation to enable ship loading at the second dock.

  On October 26, Venture Global LNG Inc. received FERC authorization to place in service liquefaction blocks 7–9 at the Calcasieu Pass LNG export terminal. All blocks of two liquefaction units each will now be in service at the facility. FERC also authorized the modified commissioning plan to place phase 3 facilities in service.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, October 24, the natural gas rig count decreased by 1 rig from a week ago to 117 rigs, as the Haynesville dropped 1 rig. The number of oil-directed rigs increased by 2 rigs from a week ago to 504 rigs. The Ardmore Woodford and Cana Woodford dropped one rig each; the Eagle Ford and the Permian added one rig each; and two rigs were added among unidentified producing regions. The total rig count, which includes 4 miscellaneous rigs, stands at 625 rigs, 143 fewer rigs than last year at this time.

Storage

• Net injections into storage totaled 79 Bcf for the week ending October 27, compared with the five-year (2018–2022) average net injections of 57 Bcf and last year's net injections of 99 Bcf during the same week. Working natural gas stocks totaled 3,779 Bcf, which is 205 Bcf (6%) more than the five-year average and 293 Bcf (8%) 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 76 Bcf to 85 Bcf, with a median estimate of 81 Bcf.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook