AlwaysFree: U.S. Energy Information Administration (EIA) - Natural Gas Weekly Update Release Date January 26, 2023

According to the U.S. Energy Information Administration (EIA) website news article published on January 26, 2023:

U.S. LNG sale and purchase agreements increased in 2022

In 2022, U.S. liquefied natural gas (LNG) suppliers of projects under development entered into contracts with buyers for about 6.0 billion cubic feet per day (Bcf/d) of LNG, according to data from the Department of Energy (DOE) and from company websites. These contracts, referred to as sale and purchase agreements (SPA), are agreements for the sale and purchase of a firm quantity of LNG over a fixed period of time, usually 10 years or longer, that stipulate the terms and conditions of the transfer between seller and buyer. The newly contracted LNG volumes will be exported from eight prospective projects—two that are under construction, four that have received regulatory approval, and two that are proposed.

The projects, by phase of development, are:

• Under construction—Corpus Christi Stage 3 and Plaquemines
• Approved—Delfin, Lake Charles LNG, Port Arthur Phase 1, and Rio Grande LNG
• Proposed—CP2 and Commonwealth LNG

Almost three-quarters (74%) of the SPAs signed with prospective projects last year are for 20-year terms that begin when the project starts commercial operations; the earliest start date would be 2024. Almost all of the agreements (92%) are for LNG cargoes to be sold on a free-on-board (FOB) basis, which means the buyer pays for and receives the LNG at the loading terminal. Destination flexibility is a common feature of most of the agreements, where the buyer can deliver the LNG to any destination as long as it complies with DOE export authorizations and U.S. law.

Although much of the contracting activity for the prospective projects occurred in 2022, Plaquemines and Rio Grande LNG entered into SPAs prior to 2022. When agreements signed before and during 2022 are included for these two projects, buyers have committed to about 90% of the Plaquemines LNG production and to about 34% of Rio Grande LNG’s production. Three other projects have approximately 50% or more of their production committed to buyers—Corpus Christi Stage 3 (60%), Lake Charles LNG (48%), and Port Arthur Phase 1 (71%).

Companies in Asia (which we expect will deliver LNG cargoes to Asia) committed to purchase 1.8 Bcf/d of the volumes contracted with these prospective LNG projects last year. Companies in Europe (which we expect will deliver LNG cargoes to Europe) committed to purchase 1.2 Bcf/d, and companies with trading affiliates (which we expect will deliver LNG cargoes to multiple destinations) committed to purchase 3.0 Bcf/d.

Concern about future natural gas supplies, particularly in Europe, grew following Russia’s full-scale invasion of Ukraine in February 2022 and contributed to the increase in contracting with new LNG projects in the United States. Europe increased its LNG imports by 66% (5.9 Bcf/d) in 2022 compared with 2021, according to data from Cedigaz, which was the result of reduced natural gas deliveries by pipeline from Russia and record-high natural gas prices at trading hubs in Europe. By expanding its LNG import capacity, Europe will be able to receive 34% more LNG in 2024 compared with 2021.

Market Highlights:

(For the week ending Wednesday, January 25, 2022)

Prices

• Henry Hub spot price: The Henry Hub spot price fell 3 cents from $3.11 per million British thermal units (MMBtu) last Wednesday to $3.08/MMBtu yesterday.
• Henry Hub futures prices: The price of the February 2023 NYMEX contract decreased 24.4 cents, from $3.311/MMBtu last Wednesday to $3.067/MMBtu yesterday. The price of the 12-month strip averaging February 2023 through January 2024 futures contracts declined 14.2 cents to $3.411/MMBtu.
• Select regional spot prices: Natural gas spot price changes were mixed this report week (Wednesday, January 18, to Wednesday, January 25), with decreases at locations in the West and increases at most locations east of the Rocky Mountains. Week-over-week price changes ranged from a decrease of $4.76/MMBtu at the PG&E Citygate to an increase of $0.99/MMBtu at Algonquin Citygate.
• Natural gas prices decreased across the West this report week but remain high. Although temperatures across the West were colder this week compared with last week, they have been rising since mid-week. The largest week-over-week decrease in price was at PG&E Citygate, where the price fell $4.76, down from $20.08/MMBtu last Wednesday to $15.32/MMBtu yesterday. Temperatures averaged 45°F in the San Jose Area on Saturday, which is 6°F lower than normal, while yesterday they averaged 54°F, which is 2°F higher than normal. The price at Sumas on the Canada-Washington border fell $3.70 from $18.23/MMBtu last Wednesday to $14.53/MMBtu yesterday. A similar pattern was observed across other major price hubs in the West. The price at SoCal Citygate in Southern California decreased $3.86 from $20.63/MMBtu last Wednesday to $16.77/MMBtu yesterday. Temperatures in the Riverside Area, inland from Los Angeles, averaged 48°F last Thursday, which is 8°F below normal, and rose over the week, averaging 56°F on Tuesday, which is normal.
• In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price went up 99 cents from $3.24/MMBtu last Wednesday to $4.23/MMBtu yesterday. Temperatures in the Boston Area averaged 35°F this week, leading to 210 heating degree days (HDDs), 32 more than last week. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 26 cents from $2.82/MMBtu last Wednesday to $3.08/MMBtu yesterday. Temperatures in the New York-Central Park Area averaged 41°F this week, leading to two more heating degree days than last week.
• The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 16 cents this report week, from $2.21/MMBtu last Wednesday to $2.37/MMBtu yesterday. The Waha Hub traded 71 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 90 cents below the Henry Hub price. Production in the Permian Basin fell by 2%, or 0.3 billion cubic feet per day (Bcf/d), this report week, according to data from S&P Global Commodity Insights.

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 $2.43 to a weekly average of $22.42/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased 42 cents to a weekly average of $19.67/MMBtu. In the same week last year (week ending January 25, 2022), the prices in East Asia and at TTF were $22.99/MMBtu and $27.65/MMBtu, respectively.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 29 cents/MMBtu, averaging $8.46/MMBtu for the week ending January 25. Ethane prices rose 1%, while average weekly natural gas prices at the Houston Ship Channel fell 4% week over week, widening the ethane premium to natural gas by 17%. Ethylene spot prices remained relatively unchanged, narrowing the ethylene to ethane premium by 1%. Propane prices rose 6%, while the weekly average price of Brent crude oil rose 2%, resulting in a 4% decrease in the propane discount relative to crude oil. Normal butane prices rose 3%, while isobutane and natural gasoline prices rose 2%.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas fell by 0.5% (0.5 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.5% (0.5 Bcf/d), and average net imports from Canada were relatively unchanged from last week.
• Demand: Total U.S. consumption of natural gas rose by 6.7% (6.2 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation climbed by 4.5% (1.4 Bcf/d) week over week. Industrial sector consumption increased by 1.7% (0.4 Bcf/d) week over week, and residential and commercial sectors consumption increased by 11.7% (4.4 Bcf/d). Natural gas exports to Mexico were relatively unchanged. Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.5 Bcf/d, or 0.1 Bcf/d higher than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Overall natural gas deliveries to U.S. LNG export terminals increased by 1.0% (0.1 Bcf/d) week over week to 12.5 Bcf/d. Feedgas deliveries to terminals in South Louisiana increased by 1.5% (0.1 Bcf/d) week over week to 8.9 Bcf/d, while deliveries to all other terminals were almost unchanged, according to data from S&P Global Commodity Insights.
• Vessels departing U.S. ports: Twenty-five LNG vessels (nine from Sabine Pass, five each from Cameron and Corpus Christi, three from Calcasieu Pass, two from Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 91 Bcf departed the United States between January 19 and January 25, according to shipping data provided by Bloomberg Finance, L.P.
• Vessels arriving at U.S. ports: One LNG vessel with a carrying capacity of 3 Bcf docked for off-loading at the Everett LNG terminal in Boston Harbor in Massachusetts between January 19 and January 25, according to shipping data provided by Bloomberg Finance, L.P. This delivery is the fourth to the terminal since November 2022.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, January 17, the natural gas rig count increased by 6 rigs from a week ago to 156 rigs. The Marcellus dropped one rig, the Haynesville and Utica each added one rig, and five rigs were added in unidentified basins. The number of oil-directed rigs decreased by 10 rigs from a week ago to 613 rigs. The Ardmore Woodford and Eagle Ford each dropped one rig, the Permian dropped two rigs, and six rigs were dropped from unidentified basins. The total rig count, which includes 2 miscellaneous rigs, now stands at 771 rigs.

Storage

• Net withdrawals from storage totaled 91 Bcf for the week ending January 20, compared with the five-year (2018–2022) average net withdrawals of 185 Bcf and last year's net withdrawals of 217 Bcf during the same week. Working natural gas stocks totaled 2,729 Bcf, which is 128 Bcf (5%) more than the five-year average and 107 Bcf (4%) 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 withdrawals of 71 Bcf to 96 Bcf, with a median estimate of 83 Bcf.
• The average rate of withdrawals from storage is 23% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 15.3 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,660 Bcf on March 31, which is 128 Bcf higher than the five-year average of 1,532 Bcf for that time of year.

More storage data and analysis can be found on the Natural Gas Storage Dashboard and the Weekly Natural Gas Storage Report.

Other Market Drivers

Yesterday, El Paso Natural Gas Company (EPNG) posted an update to its Force Majeure notice of August 15, 2021, related to the pipeline failure on Line 2000. EPNG has completed repair work on Line 2000 and submitted a request yesterday to the Pipeline and Hazardous Materials Safety Administration (PHMSA) to lift the current pressure restriction so that the line can return to commercial service.