Natural Gas

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price rose 1 cent from $2.10 per million British thermal units (MMBtu) last Wednesday to $2.11/MMBtu yesterday. After averaging $1.91/MMBtu for the first five trading days in June, the Henry Hub spot price rose above $2.00 yesterday for the first time this month.
• Henry Hub futures prices: The price of the July 2023 NYMEX contract increased 6.3 cents, from $2.266/MMBtu last Wednesday to $2.329/MMBtu yesterday. The price of the 12-month strip averaging July 2023 through June 2024 futures contracts climbed 8 cents to $3.040/MMBtu.
• Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, May 31, to Wednesday, June 7) but fell at one location in the Northeast. Price changes at major pricing hubs this report week ranged from a decrease of $3.28/MMBtu at Algonquin Citygate to an increase of $1.11/MMBtu at SoCal Citygate.
• Prices in West Coast markets remain the highest of all major pricing hubs this report week. The price at PG&E Citygate in Northern California rose 65 cents, up from $3.07/MMBtu last Wednesday to $3.72/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $1.11 from $2.18/MMBtu last Wednesday to $3.29/MMBtu yesterday. The price at Sumas on the Canada-Washington border rose 47 cents from $1.70/MMBtu last Wednesday to $2.17/MMBtu yesterday. Natural gas consumption in the Western region increased by 13%, or 0.9 billion cubic feet per day (Bcf/d), which was led by a 38% (1.0 Bcf/d) increase in consumption in the electric power sector, according to data from S&P Global Commodity Insights. According to our Hourly Electric Grid Monitor, from the California Independent System Operator, the share of natural gas-fired power generation in California increased from an average of 20% last report week to an average of 33% this week, reaching more than 42% on June 7. In the Seattle area, from Puget Sound Energy (the largest investor-owned utility in the Pacific Northwest), the share of natural gas-fired power generation increased from an average of 27% last report week to an average of almost 60% this week, reaching more than 68% on June 7. Natural gas-fired power generation rose to compensate for declines in wind- and solar-power generation in California and wind- and hydro-power generation in the Pacific Northwest.
• At the Algonquin Citygate, which serves Boston-area consumers, the price fell by $3.28 from $4.90/MMBtu last Wednesday to $1.62/MMBtu yesterday. Last Wednesday’s multi-month high was bracketed by $1.78/MMBtu on Tuesday, May 30 and $1.90/MMBtu on Thursday, June 1, and the Algonquin Citygate has been trading below $2.00/MMBtu every day this report week along with other Northeast trading hubs. In the Appalachia production region, the Tennessee Zone 4 Marcellus spot price increased 24 cents from $1.08/MMBtu last Wednesday to $1.32/MMBtu yesterday. Due to a forecast of milder temperatures and resulting low natural gas demand, Tennessee Gas Pipeline issued an operational flow order to maintain pipeline system integrity, effective June 9, whereby operators are required to balance pipeline receipts and deliveries.

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 fell 6 cents to a weekly average of $9.25/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands fell 3 cents to a weekly average of $7.95/MMBtu. In the same week last year (week ending June 8, 2022), the prices were $23.41/MMBtu in East Asia and $25.68/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 8 cents/MMBtu, averaging $5.76/MMBtu for the week ending June 7. Weekly average ethane prices fell 3%, while natural gas prices at the Houston Ship Channel fell 8%, widening the ethane premium to natural gas by 7% week over week. Ethylene spot prices fell by 6%, decreasing the ethylene to ethane premium by 7%. Propane prices rose 2%, following Brent crude oil prices, which also rose 2%, increasing the propane discount relative to crude oil by 2%. The normal butane price fell 2%, the isobutane price fell 4%, and natural gasoline fell 3%.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.6% (0.7 Bcf/d), and average net imports from Canada increased by 18.6% (0.8 Bcf/d) from last week as imports returned to levels seen before the wildfires in Western Canada disrupted natural gas flows.
• Demand: Total U.S. consumption of natural gas rose by 7.5% (4.7 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 17.6% (5.4 Bcf/d) week over week. Industrial sector consumption decreased by 0.3% (0.1 Bcf/d), and residential and commercial sector consumption declined by 5.8% (0.6 Bcf/d). Natural gas exports to Mexico were essentially unchanged, and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.9 Bcf/d, or 1.4 Bcf/d lower than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Overall weekly average natural gas deliveries to U.S. LNG export terminals decreased by 10.5% (1.4 Bcf/d) week over week to average 11.9 Bcf/d this report week, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Texas were essentially unchanged at 4.3 Bcf/d, while deliveries to terminals in South Louisiana decreased by 17.4% (1.4 Bcf/d) to 6.5 Bcf/d largely due to decreased flows to the Sabine Pass terminal. Maintenance scheduled for June 5 through June 9 on the Gillis compressor station on the Creole Trail Pipeline accounts for some of the decline in natural gas deliveries to Sabine Pass. Natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged at 1.2 Bcf/d. For the first time since the beginning of the year, weekly average natural gas deliveries to LNG export terminals fell below 12 Bcf/d.
• Vessels departing U.S. ports: Twenty-two LNG vessels (six from Sabine Pass; four each from Corpus Christi and Freeport; three from Cameron; two each from Calcasieu Pass and Cove Point; and one from Elba Island) with a combined LNG-carrying capacity of 81 Bcf departed the United States between June 1 and June 7, according to shipping data provided by Bloomberg Finance, L.P.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, May 30, the natural gas rig count was unchanged from a week ago at 137 rigs; the Haynesville dropped two rigs, while the Permian added two rigs. The number of oil-directed rigs decreased by 15 rigs from a week ago to 555 rigs. The Permian dropped four rigs, the Eagle Ford and Williston each dropped two rigs, the Ardmore Woodford and Cana Woodford each dropped one rig, and five rigs were dropped in unidentified producing basins. The total rig count, which includes 4 miscellaneous rigs, stands at 696, 31 fewer rigs than last year at this time. The total rig count fell below 700 rigs for the first time since April 29, 2022.

Storage

• Net injections into storage totaled 104 Bcf for the week ending June 2, compared with the five-year (2018–2022) average net injections of 100 Bcf and last year's net injections of 99 Bcf during the same week. Working natural gas stocks totaled 2,550 Bcf, which is 353 Bcf (16%) more than the five-year average and 562 Bcf (28%) 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 106 Bcf to 124 Bcf, with a median estimate of 116 Bcf.
• The average rate of injections into storage is 8% higher 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 9.3 Bcf/d for the remainder of the refill season, the total inventory would be 3,948 Bcf on October 31, which is 353 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