LNG exports from North America are set to expand with new projects
Over the next five years, we expect North America’s liquefied natural gas (LNG) export capacity to expand by 12.9 billion cubic feet per day (Bcf/d) as Mexico and Canada place into service their first LNG export terminals and the United States adds to its 11.4 Bcf/d of existing LNG capacity. By the end of 2027, we estimate LNG export capacity will grow by 1.1 Bcf/d in Mexico, 2.1 Bcf/d in Canada, and 9.7 Bcf/d in the United States from a total of ten new projects across the three countries. Mexico. Three projects with a combined LNG export capacity of 1.1 Bcf/d are currently under construction—Fast LNG Altamira offshore and onshore, Fast LNG Lakach on the east coast, and Energia Costa Azul on the west coast. Fast LNG Altamira consists of three units, each with a capacity to liquefy up to 0.18 Bcf/d. The first unit will be located offshore and the other two units will be installed onshore at the Altamira LNG regasification terminal. These units will be supplied by natural gas from the United States delivered via the Sur de Texas-Tuxpan pipeline. The first LNG exports from the offshore unit are expected in December 2023, and LNG exports from the onshore units are expected in 2025. The Fast LNG Lakach unit (capacity 0.18 Bcf/d) will be installed offshore of Veracruz, Mexico, at the nearby Lakach natural gas field. First LNG exports are expected in 2026. The Energia Costa Azul LNG export terminal is located at the site of the existing LNG regasification terminal in Baja California, western Mexico. The LNG export capacity will be 0.4 Bcf/d for Phase 1 (under construction) and 1.6 Bcf/d for Phase 2 (proposed). The export terminal will be supplied with natural gas from the Permian Basin in the United States. Developers have proposed other LNG export projects for Mexico’s west coast, including Saguaro Energia LNG, Salina Cruz FLNG, and Vista Pacifico LNG, which have a combined capacity over 2.7 Bcf/d. These projects will use relatively low-cost natural gas imported from the United States for LNG exports to Asian markets. However, none of these proposed projects has reached a final investment decision yet. Canada. Two LNG export projects with a combined capacity of 2.1 Bcf/d are under construction in British Columbia on Canada’s west coast. LNG Canada (with an export capacity of 1.8 Bcf/d) is scheduled to begin service in 2025, and Woodfibre LNG (0.3 Bcf/d) is scheduled to begin service in 2027. Both export terminals will be supplied with natural gas from western Canada. In addition, Canada’s National Energy Board (NEB) has authorized an additional 18 LNG export projects with a combined capacity of 29 Bcf/d. United States. Five LNG export projects are currently under construction with a combined 9.7 Bcf/d of LNG export capacity—Golden Pass, Plaquemines, Corpus Christi Stage III, Rio Grande, and Port Arthur. LNG exports from Golden Pass LNG and Plaquemines LNG are expected to start in 2024.
Henry Hub spot price: The Henry Hub spot price fell 4 cents from $2.90 per million British thermal units (MMBtu) last Wednesday to $2.86/MMBtu yesterday. Henry Hub futures price: The price of the November 2023 NYMEX contract decreased 4.6 cents, from $3.056/MMBtu last Wednesday to $3.010/MMBtu yesterday. The price of the 12-month strip averaging November 2023 through October 2024 futures contracts declined 6 cents to $3.315/MMBtu. Select regional spot prices: Natural gas spot prices across the United States declined modestly this report week (Wednesday, October 18, to Wednesday, October 25) with the exception of the West Coast, where prices changed substantially. The price at SoCal Citygate in Southern California decreased $6.39 from $11.70/MMBtu last Wednesday to $5.31/MMBtu yesterday as flows of natural gas into Southern California increased. The El Paso Natural Gas Company lifted the force majeure on Line 1104 on October 20, contributing to a 9% (0.4 billion cubic feet per day [Bcf/d]) increase in natural gas flows from the Desert Southwest into California compared with last week, according to data from S&P Global Commodity Insights. The price at SoCal Citygate decreased 33% ($3.74) from $11.37/MMBtu on October 19 to $7.63/MMBtu on October 20. Temperatures also declined in recent days in the Riverside Area, inland from Los Angeles, and averaged 65°F yesterday, resulting in 0 heating and cooling degree days. Prices in Northern California and the Pacific Northwest rose this week as flows of natural gas into the region decreased and temperatures declined. The price at PG&E Citygate in Northern California rose 10 cents, up from $7.83/MMBtu last Wednesday to $7.93/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, rose $2.92 from $2.23/MMBtu last Wednesday to $5.15/MMBtu yesterday. The price at Sumas on the Canada-Washington border rose $3.94 from $2.10/MMBtu last Wednesday to $6.04/MMBtu yesterday. A maintenance event on the Westcoast Pipeline (Notice 57363), which moves natural gas from the northeast British Columbia production area south to the Washington State border at Huntington, reduced capacity by approximately 0.1 Bcf/d. The capacity constraint, combined with colder-than-normal weather in British Columbia, resulted in a 10% (0.4 Bcf/d) net decline in flows of natural gas from Canada into the Pacific Northwest. In turn, net flows of natural gas from the Pacific Northwest into California declined 20% (0.4 Bcf/d), according to data from S&P Global Commodity Insights. The price at Opal Hub in southwest Wyoming, which transports natural gas from the Rocky Mountain production region to West Coast consumption markets, rose $2.07 from $2.43/MMBtu last Wednesday to $4.50/MMBtu yesterday. The Williams company announced a deficiency period at the Kemmerer compressor station near the western border of Wyoming on Tuesday as primary nomination requests at the location exceeded the available capacity of almost 0.6 Bcf/d. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell $1.57 this report week, from $1.96/MMBtu last Wednesday to $0.39/MMBtu yesterday. The Waha Hub traded $2.47 below the Henry Hub price yesterday, compared with last Wednesday when it traded 94 cents below the Henry Hub price. The price at Waha Hub was negative on Monday and Tuesday this week. The last time the price at Waha Hub was negative was in July. Net flows of natural gas out of West Texas fell 6% (0.8 Bcf/d), driven by a decline of 18% (1.0 Bcf/d) in net flows of natural gas from West Texas to North Texas. The Permian Highway Pipeline, which delivers natural gas from West Texas to the Gulf Coast, operated at reduced capacity because of inspections and maintenance at the Big Lake compressor station.
Daily spot prices by region are available on the EIA website.
International futures prices: International natural gas futures price changes were mixed 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 $1.71 to a weekly average of $18.21/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased 12 cents to a weekly average of $15.65/MMBtu. In the same week last year (week ending October 26, 2022), the prices were $31.52/MMBtu in East Asia and $31.61/MMBtu at TTF. Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 16 cents/MMBtu, averaging $7.05/MMBtu for the week ending October 25. Weekly average ethane prices fell 6%, while weekly average natural gas prices at the Houston Ship Channel rose 2% week over week. The ethane premium to natural gas fell 15%. Ethylene spot prices fell 1%, and the ethylene premium to ethane rose 3%. The average weekly propane price fell 5%, while the Brent crude oil price remained relatively unchanged. 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 fell by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.1% (0.1 Bcf/d) to a weekly average of 102.6 Bcf/d, and average net imports from Canada decreased by 3.8% (0.2 Bcf/d) from last week. Demand: Total U.S. consumption of natural gas fell by 1.6% (1.1 Bcf/d) compared with the previous report week, driven by a decline in the residential and commercial sectors, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation rose by 2.5% (0.8 Bcf/d) week over week. Industrial sector consumption decreased by 1.1% (0.2 Bcf/d) week over week. In the residential and commercial sectors, consumption declined by 10.2% (1.7 Bcf/d) as warmer temperatures in most consuming regions decreased demand for space heating. Natural gas exports to Mexico increased 2.5% (0.2 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 13.7 Bcf/d, or 0.6 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals fell by 4.1% (0.6 Bcf/d) week over week, averaging 13.7 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Texas declined by 2.9% (0.1 Bcf/d) to 4.1 Bcf/d. Natural gas deliveries to terminals in South Louisiana declined by 4.4% (0.4 Bcf/d) to 8.5 Bcf/d, and natural gas deliveries to terminals outside the Gulf Coast decreased by 2.6% (less than 0.1 Bcf/d) to 1.1 Bcf/d. Vessels departing U.S. ports: Twenty-seven LNG vessels (nine from Sabine Pass; five from Freeport; four from Corpus Christi; three each from Cameron and Calcasieu Pass; two from Cove Point; and one from Elba Island) with a combined LNG-carrying capacity of 97 Bcf departed the United States between October 19 and October 25, according to shipping data provided by Bloomberg Finance, L.P.
The net injections into storage totaled 74 Bcf for the week ending October 20, compared with the five-year (2018–2022) average net injections of 66 Bcf and last year’s net injections of 61 Bcf during the same week. Working natural gas stocks totaled 3,700 Bcf, which is 183 Bcf (5%) more than the five-year average and 313 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 73 Bcf to 89 Bcf, with a median estimate of 82 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 7.1 Bcf/d for the remainder of the refill season, the total inventory would be 3,778 Bcf on October 31, which is 183 Bcf higher than the five-year average of 3,595 Bcf for that time of year.