U.S. natural gas consumption reaches daily record high in December 2022
On December 23, 2022, estimated total consumption of natural gas in the U.S. Lower 48 states reached a daily record high of 141.0 billion cubic feet (Bcf), exceeding the previous daily record high of 137.4 Bcf set on January 1, 2018, according to data from S&P Global Commodity Insights. Total consumption includes natural gas consumed in the residential, commercial, industrial, and power generation sectors. Below-normal temperatures in mid- to late-December increased demand for residential and commercial heating, as well as for electric power generation, and contributed to a steep weather-related decline in natural gas production. From December 21 through December 26, a historic winter storm moved across North America, bringing blizzards, high winds, and extremely cold temperatures to large areas of the United States. Well-below-normal temperatures were accompanied by record levels of consumption of natural gas, mostly to meet heating demand in the residential and commercial sectors. From December 21 through December 26, combined consumption in the residential and commercial sectors averaged 60.9 billion cubic feet per day (Bcf/d), up 55% compared with the previous five-year (2017-2021) average of 39.2 Bcf/d for the same period. Consumption in the electric power sector averaged 37.8 Bcf/d from December 21 through December 26, up 45% compared with the previous five-year average of 26.0 Bcf/d for the same period. The surge in demand was met through increased electric power generation from natural gas, coal, wind, and oil. The rapid increase in electric power demand caused problems for electric grid operators, as electricity loads increased significantly while freeze-induced outages reduced operational capacity in some markets. The Tennessee Valley Authority (TVA) increased electric power generation to a winter record-high for the system, and both TVA and Duke Energy (the largest electricity supplier in the Carolinas) instituted rolling outages across their service territories to protect the grid. Both the Electric Reliability Council of Texas (ERCOT) and the Southwest Power Pool (SPP) generated winter record-high electric power during the storm. In New England, natural gas pipeline constraints limit the amount of natural gas that can be delivered to power plants, and natural gas delivery is prioritized to homes and buildings for space heating. Because of reduced delivery of natural gas to power plants during the winter storm, the share of power generation in New England met by natural gas fell from an average of 57% for December 21 through December 22 to 24% from December 23 through December 26. A rise in oil-fired electric power generation offset the loss of natural gas-fired generation to help meet electricity demand in the New England region, supplying nearly 41% of all electric power generation during select hours on December 24, up from nearly zero over the four days prior to December 21. While consumption of natural gas surged, production fell rapidly, creating an imbalance that led to large withdrawals from storage and increased natural gas pipeline imports from Canada. Dry natural gas production in the Lower 48 states fell from 98.6 Bcf on December 21 to a low of 82.5 Bcf on December 24, a decline of 16.1 Bcf, or 16.3%, before increasing to 99.5 Bcf on December 31. The last time the United States saw such a large and rapid decline in dry natural gas production was during a February 2021 winter storm. Withdrawals from working underground storage of natural gas across the Lower 48 states were 213.0 Bcf for the week ending December 23 and 221.0 Bcf for the week ending December 30, compared with last year’s withdrawals of 136.0 Bcf for the week ending December 24, 2022 and 31.0 Bcf for the week ending December 31, 2022. Natural gas pipeline imports from Canada helped support reliability, supplying 10.4 Bcf of natural gas to the United States on December 24, the highest volume of daily imports from Canada since February 2007, according to data from S&P Global Commodity Insights.
Prices – Henry Hub spot price: The Henry Hub spot price fell 24 cents from $3.35 per million British thermal units (MMBtu) last Wednesday to $3.11/MMBtu yesterday. Henry Hub futures prices: The price of the February 2023 NYMEX contract decreased 36 cents, from $3.671/MMBtu last Wednesday to $3.311/MMBtu yesterday. The price of the 12-month strip averaging February 2023 through January 2024 futures contracts declined 19.4 cents to $3.553/MMBtu. Select regional spot prices: Natural gas spot price changes were mixed this report week (Wednesday, January 11, to Wednesday, January 18), with increases at locations in the West and decreases at most locations east of the Rocky Mountains. Week-over-week price changes ranged from an increase of $8.57/MMBtu at Sumas to a decrease of $0.16/MMBtu at the Chicago Citygate. Natural gas prices remain elevated in the West this report week. The largest week-over-week increase was at Sumas on the Canada-Washington border where the price increased $8.57 from $9.66/MMBtu last Wednesday to $18.23/MMBtu yesterday. Both Westcoast Energy Inc. and Gas Transmission Northwest (pipelines that deliver natural gas into the Pacific Northwest from Canada at Sumas and Kingsgate, Idaho, respectively) reported curtailments on their systems. The price at PG&E Citygate in Northern California rose $1.30, up from $18.78/MMBtu last Wednesday to $20.08/MMBtu yesterday. At Malin, Oregon, the northern delivery point into the PG&E service territory, the price rose $2.67 from $16.07/MMBtu last Wednesday to $18.74/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $2.47 from $18.16/MMBtu last Wednesday to $20.63/MMBtu yesterday. Temperatures in the Riverside Area, inland from Los Angeles, averaged 51°F this week, 5°F below normal, which resulted in 94 heating degree days (HDD), 28 HDDs more than normal. Natural gas consumption in the West increased 1% this week, or 0.1 billion cubic feet per day (Bcf/d), according to data from S&P Global Commodity Insights. An increase in consumption of 7% (0.3 Bcf/d) in the residential and commercial sectors was partly offset by a decrease in the electric power sector of 5% (0.2 Bcf/d). Compared with the same week last year, natural gas consumption is 7% higher. At the Chicago Citygate, the price decreased 16 cents from $3.15/MMBtu last Wednesday to $2.99/MMBtu yesterday. Temperatures in the Chicago Area averaged 37°F this report week, 12°F above normal, which resulted in 193 HDDs, 88 HDDs fewer than normal. According to data from S&P Global Commodity Insights, natural gas consumption in the Mid-Continent decreased 4% (1.0 Bcf/d) week over week, including a 6% decrease (0.3 Bcf/d) in the electric power sector and a 5% decrease (0.6 Bcf/d) in the residential and commercial sectors. Industrial consumption also fell by 1% (0.1 Bcf/d). In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price went down 14 cents from $3.38/MMBtu last Wednesday to $3.24/MMBtu yesterday. Although relatively unchanged week over week, Algonquin Citygate prices fluctuated during the week, and recorded a weekly high of $7.15/MMBtu on January 13. Other prices in the Northeast were relatively stable, remaining below $3/MMBtu most of the week. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 3 cents from $2.79/MMBtu last Wednesday to $2.82/MMBtu yesterday. The Tennessee Zone 4 Marcellus spot price increased 8 cents from $2.50/MMBtu last Wednesday to $2.58/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell 5 cents from $2.48/MMBtu last Wednesday to $2.43/MMBtu yesterday. Natural gas consumption in the Northeast was essentially unchanged at 25.8 Bcf/d this week, according to data from S&P Global Commodity Insights. Compared with the same week last year, natural gas consumption is 10% lower.
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 $2.82 to a weekly average of $24.85/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased $1.92 to a weekly average of $20.10/MMBtu. In the same week last year (week ending January 19, 2022), the prices in East Asia and at TTF were $27.38/MMBtu and $27.24/MMBtu, respectively. Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 51 cents/MMBtu, averaging $8.17/MMBtu for the week ending January 18. Ethane prices fell 7%, while average weekly natural gas prices at the Houston Ship Channel fell 1% week over week, narrowing the ethane premium to natural gas by 19%. Ethylene spot prices rose 5%, widening the ethylene to ethane premium by 39%. Propane prices rose 12%, while the weekly average price of Brent crude oil rose 7%, resulting in a 2% decrease in the propane discount relative to crude oil. Normal butane prices rose 7%, and isobutane prices rose 6%. Natural gasoline prices rose 11%.
Supply and Demand
Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 0.1% (less than 0.1 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.3% (0.3 Bcf/d), and average net imports from Canada decreased by 4.9% (0.3 Bcf/d) from last week. Demand: Total U.S. consumption of natural gas rose by 0.5% (0.5 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 1.0% (0.3 Bcf/d) week over week. Industrial sector consumption was essentially unchanged, and in the residential and commercial sectors, consumption increased by 0.4% (0.2 Bcf/d). Although total consumption increased week over week, consumption in the first 18 days of January was 12% lower compared with the same days last year. Above-normal temperatures throughout most of the country have led to reduced demand for natural gas for space heating compared with a year ago. Natural gas exports to Mexico increased 0.7% (less than 0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.4 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 were essentially unchanged, increasing by less than 0.1 Bcf/d week over week to average 12.4 Bcf/d this report week, according to data from S&P Global Commodity Insights. Vessels departing U.S. ports: Twenty-two LNG vessels (nine from Sabine Pass, five from Corpus Christi, and four each from Cameron and Calcasieu Pass) with a combined LNG-carrying capacity of 82 Bcf departed the United States between January 12 and January 18, according to shipping data provided by Bloomberg Finance, L.P.
The net withdrawals from storage totaled 82 Bcf for the week ending January 13, compared with the five-year (2018–2022) average net withdrawals of 156 Bcf and last year’s net withdrawals of 203 Bcf during the same week. Working natural gas stocks totaled 2,820 Bcf, which is 34 Bcf (1%) more than the five-year average and 19 Bcf (1%) lower 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 13 Bcf to 89 Bcf, with a median estimate of 73 Bcf. The average rate of withdrawals from storage is 17% 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 16.3 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,566 Bcf on March 31, which is 34 Bcf higher than the five-year average of 1,532 Bcf for that time of year.