2021 industrial natural gas consumption on trend to exceed the 5-year average:
Natural gas consumption in the U.S. industrial sector averaged 22.4 billion cubic feet per day (Bcf/d) in the first seven months of 2021, which is 0.4 Bcf/d higher than during the same period in 2020 and 0.2 Bcf/d above the five-year (2016-2020) average, according to our Natural Gas Monthly. After reaching the highest levels on record in 2018 and 2019, when industrial sector natural gas consumption averaged in excess of 23.1 Bcf/d in the first seven months of both years, it declined in 2020 as a result of various COVID-19 mitigation measures. In March 2020, economic activity declined, resulting in an associated decline in output among industries that are major consumers of natural gas, namely the metals, food and beverage products, petroleum and coal products, paper, and chemicals industries, which together account for nearly 85% of natural gas used in U.S. manufacturing, according to our Manufacturing Energy Consumption Survey (MECS). Since the second half of 2020, both industrial sector activity and consumption of natural gas have been increasing. In January 2021, industrial sector natural gas consumption averaged 25.3 Bcf/d, which is 0.1 Bcf/d above January 2020 and 0.5 Bcf above the five-year average for the month of January. However, because of extreme winter weather, especially in Texas, industrial natural gas consumption in February fell to the lowest level for the month since 2017 and remained low in March. The severe weather resulted in production freeze-offs, record-high natural gas prices, and natural gas delivery curtailments to large industrial natural gas consumers. The disruption to industrial activity persisted through the second half of February 2021 and into March, leading industrial sector natural gas consumption to decline 8% in February and 7% in March, compared with the same months in 2019. From April to July 2021, the most recent month for which EIA survey data are available, average natural gas consumption in the industrial sector surpassed 2020 levels and the five-year average for the same timeframe. This growth occurred despite gradually rising prices at the natural gas benchmark Henry Hub, which at $3.26 per million British thermal units (MMBtu) and $3.84/MMBtu in June and July of 2021, respectively, was at its highest level for the same months since 2014. For the rest of this year, we forecast that industrial natural gas consumption will average 24.1 Bcf/d, resulting in 2021 annual consumption reaching 23.1 Bcf/d, approximately 4% above 2020 and the five-year average. The continuing growth in natural gas consumption for both fuel and feedstock in the industrial sector coincides with strong economic activity in the chemical sector, which, according to MECS, accounts for close to 37% of all industrial sector natural gas consumption. In both the chemicals sector and the petroleum and coal products sector, which accounts for 17% of industrial sector natural gas consumption, natural gas competes with petroleum products as both a feedstock and as fuel. Though higher than in recent years, current natural gas prices remain well below crude oil, which on a heating-value-equivalent basis averaged approximately $13/MMBtu through June and July.
Overview:
Natural gas spot prices rose at most locations this report week (Wednesday, September 29 to Wednesday, October 6). The Henry Hub spot price rose from $5.63 per million British thermal units (MMBtu) last Wednesday to $5.95/MMBtu yesterday. International natural gas prices rose for the sixth consecutive week. Bloomberg Finance, L.P. reports that swap prices for November liquefied natural gas (LNG) cargos in East Asia rose to a weekly average of $32.48/MMBtu this report week, the highest weekly average on record since January 2020 and $4.52/MMBtu above last week’s average of $27.96/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, day-ahead prices averaged $32.28/MMBtu this report week, the highest weekly average on record since September 2007 and up $7.05/MMBtu from last week’s average of $25.23/MMBtu. In the same week last year (week ending October 7, 2020), prices in East Asia and at TTF were at $5.06/MMBtu and $4.39/MMBtu, respectively. The price of the November 2021 NYMEX contract increased 20¢, from $5.477/MMBtu last Wednesday to $5.675/MMBtu yesterday, after rising to a high of $6.312/MMBtu on Tuesday. The price of the 12-month strip averaging November 2021 through October 2022 futures contracts climbed 16¢ to $4.665/MMBtu. Natural gas futures for delivery in December, January, and February of the current winter all settled at approximately $5.80/MMBtu yesterday, lower than on Tuesday, when these contracts settled at $6.432/MMBtu (December), $6.522/MMBtu (January), and $6.407/MMBtu (February). The January 3-month contract settlement price was the highest since October 29, 2008, when the January contract settled at $7.060/MMBtu. The net injections to working gas totaled 118 billion cubic feet (Bcf) for the week ending October 1. Working natural gas stocks totaled 3,288 Bcf, which is 14% lower than the year-ago level and 5% lower than the five-year (2016–2020) average for this week. The natural gas plant liquids (NGPL) composite price at Mont Belvieu, Texas, rose by 77¢/MMBtu, averaging $12.36/MMBtu for the week ending October 6. Average weekly ethane prices increased 7% this report week, in line with natural gas prices at the Houston Ship Channel, which rose just under 8%. Ethylene prices, however, dropped 7%, resulting in the ethane-to-ethylene cracking margin falling to its lowest level since the first week in July. Brent crude oil prices rose 4% this report week, resulting in higher prices of all heavy NGPLs. Natural gasoline prices, which most closely align with crude oil prices, also rose 4% this report week. Price increases for butanes slightly outpaced the rise in the crude oil price. The normal butane price rose 5% and the isobutane price rose 6% as a result of rising demand for gasoline blending. Propane prices rose 8% over the first week of the winter heating season, reflecting strong demand from domestic and international markets. Propane is used as a primary space heating fuel by approximately 5% of occupied U.S. households and by a larger share of households in the Midwest and Northeast. Regional prices, as well retail prices, are available in the Winter Propane Market Update on the Winter Heating Fuels page. According to Baker Hughes, for the week ending Tuesday, September 28, the natural gas rig count remained flat at 99. No changes were reported in any major production basins. The number of oil-directed rigs rose by 7 to 428 from 421 last report week. The largest gains were reported in Louisiana, where the off-shore rig count rose by 3 to a total of 10 rigs, which is 4 rigs less than before Hurricane Ida. Louisiana offshore rigs dropped to zero in the week Hurricane Ida made landfall in late August. The Permian Basin also gained three rigs, one in Texas and two in New Mexico. A one-rig gain in the Anadarko play in Oklahoma rounded out the oil-directed rig gains. The total rig count increased by 7, and it now stands at 528.
Prices/Supply/Demand:
Gulf Coast prices are volatile this week. This report week (Wednesday, September 29 to Wednesday, October 6), the Henry Hub spot price rose 32¢ from $5.63/MMBtu last Wednesday to $5.95/MMBtu yesterday. Henry Hub spot price movements were volatile this week, first decreasing to a weekly low of $5.55/MMBtu on Thursday, September 30, and then increasing to a weekly high of $6.23/MMBtu on Tuesday, October 5. Tuesday’s high was the highest level since mid-February when prices rose as a result of a winter storm that impacted natural gas production and distribution across the Gulf Coast. Planned maintenance on the McComb pool point (notice ID 5029571) of the Gulf South Pipeline, which began on Monday, October 4, will reduce flows on the pipeline by as much as 300 million cubic feet per day (MMcf/d) of capacity until October 9. The Gulf South Pipeline transports natural gas from producing basins in Texas and northern Louisiana to the Gulf Coast. Production in North Louisiana began to drop on October 5, following the start of maintenance. According to data from IHS Markit, production in North Louisiana fell 0.2 Bcf/d from 9.1 Bcf/d on October 4 to 8.9 Bcf/d yesterday. Midwest prices rise, reflecting price increases across the country. At the Chicago Citygate, the price increased 46¢ from $5.29/MMBtu last Wednesday to $5.75/MMBtu yesterday after reaching a weekly high of $6.05/MMBtu on Tuesday. Consumption in the Midwest remained relatively flat, reflecting shoulder-season weather. Temperatures across the Midwest were above normal, which for this time of season means relatively mild. In the Chicago area, the daily average temperature yesterday was 66°F, or 8°F above normal, resulting in zero heating degree days (HDD—a measure of heating demand), compared with 8 HDDs under a normal weather scenario. The mild weather resulted in Midwest consumption rising 0.1 Bcf/d; a 0.7 Bcf/d increase in natural gas consumption for power generation was mostly offset by a 0.5 Bcf/d decline in residential and commercial sector consumption. California prices remain elevated but at a lower premium to the Henry Hub than last week. The price at PG&E Citygate in Northern California rose 19¢, up from $7.03/MMBtu last Wednesday to $7.22/MMBtu yesterday. The price at the PG&E Citygate was $1.27/MMBtu above the Henry Hub price, which is less than the $1.40/MMBtu premium reported last Wednesday. The price at SoCal Citygate in Southern California decreased 50¢ from $7.09/MMBtu last Wednesday to $6.59/MMBtu yesterday. The price premium at SoCal Citygate to the Henry Hub declined from $1.46/MMBtu last Wednesday to $0.64/MMBtu yesterday. SoCal Gas reports continuing maintenance at Aliso Canyon, the largest natural gas storage facility in the region, reducing the ability to inject natural gas into storage by 545 MMcf/d. The current outage, which is scheduled to end October 13, has reduced the ability of the natural gas system in the region to balance through storage. Prices in the Northeast rise in line with prices at other major hubs. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 44¢ from $4.90/MMBtu last Wednesday to $5.34/MMBtu yesterday. At the Transcontinental Pipeline (Transco) Zone 6 trading point for New York City, the price increased 52¢ from $4.69/MMBtu last Wednesday to $5.21/MMBtu yesterday. Similar to prices throughout the country, prices at Algonquin Citygate and Transco Zone 6 reached weekly highs on Tuesday, at $5.46/MMBtu and $5.33/MMBtu, respectively. Temperatures in New York’s Central Park averaged 65°F yesterday. The daily Central Park minimum and maximum was close to the average, at 61°F to 69°F, a significantly narrower range than the normal 55°F to 68°F, which resulted in zero HDDs and CDDs (cooling degree days—a measure of cooling demand, which is met with electric-powered air conditioning), compared with 5 HDDs and 1 CDD under a normal-weather scenario. The mild temperatures resulted in natural gas consumption remaining relatively flat week over week. IHS Markit estimates consumption in New England declined on average by less than 50 MMcf/d week over week and rose in the New York/New Jersey region by slightly more than 100 MMcf/d. Total demand in the Atlantic region also remained relatively flat, reflecting the mild weather and reduced export demand. Berkshire Hathaway Energy’s Gas Transmission and Storage (GHE GT&S) reports volumes of feed gas delivered to the Cove Point LNG export terminal in Maryland remained at 2 MMcf/d this report week. Prior to maintenance (notice ID 124681) at the terminal, which is scheduled to last from September 20 through October 10, feed gas volumes averaged more than 750 MMcf/d. Prices in the Appalachia Basin production region increase in line with prices in other regions. The Tennessee (TGP) Zone 4 Marcellus spot price increased 46¢ from $4.60/MMBtu last Wednesday to $5.06/MMBtu yesterday. The price at Eastern Gas South in Southwest Pennsylvania rose 45¢ from $4.65/MMBtu last Wednesday to $5.10/MMBtu yesterday. Prices at both hubs fell to weekly lows on Friday, reaching $2.45/MMBtu at TGP Zone 4 Marcellus and $3.57/MMBtu at Eastern Gas South, reflecting anticipated reduced demand for the forthcoming weekend in the Northeast and Midwest consuming regions as a result of unseasonably mild temperatures (see Midwest and Northeast sections above). Prices in the Permian Basin increase more than Gulf Coast prices as pipeline maintenance begins to constrain production. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 53¢ this report week, from $5.05/MMBtu last Wednesday to $5.58/MMBtu yesterday. The Waha Hub traded 37¢/MMBtu below the Henry Hub price yesterday compared with last Wednesday, when it traded 58¢/MMBtu below the Henry Hub price. Production in the Permian-Delaware Basin decreased 2.9% this week according to data from IHS Markit. In addition, maintenance on the WT-1 compressor station (notice ID 86158) on the Transwestern Pipeline in New Mexico began yesterday. U.S. supply of natural gas remained relatively flat this report week. According to data from IHS Markit, the average total supply of natural gas fell by 0.4% compared with the previous report week. Average net imports from Canada decreased by 5.8% (0.3 Bcf/d) compared with the previous report week. Dry gas production was relatively flat, falling less than 0.1%. U.S. natural gas consumption increases week over week on a substantial increase in power generation. Total U.S. consumption of natural gas rose by 3.9% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 8.3%, or 2.4 Bcf/d, as a result of warmer-than-average temperatures across the Midwest and the South. Industrial sector consumption decreased by 0.6% week over week, balanced against a week-over-week increase in the residential and commercial sectors of 0.5%. Natural gas exports to Mexico decreased 4.3% week over week. Natural gas deliveries to U.S. liquefied natural gas export facilities (LNG pipeline receipts) averaged 10.0 Bcf/d, or 0.2 Bcf/d lower than last week. U.S. LNG exports increase week over week. Twenty LNG vessels (eight from Sabine Pass, four each from Cameron and Corpus Christi, three from Freeport, and one from Elba Island) with a combined LNG-carrying capacity of 74 Bcf departed the United States between September 30 and October 6, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 118 Bcf for the week ending October 1, compared with the five-year (2016–2020) average net injections of 81 Bcf and last year’s net injections of 75 Bcf during the same week. Working natural gas stocks totaled 3,288 Bcf, which is 176 Bcf lower than the five-year average and 532 Bcf 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 injections of 92 Bcf to 123 Bcf, with a median estimate of 110 Bcf. The average rate of injections into storage is 9% lower than the five-year average so far this refill season (April through October). If the rate of injections into storage matched the five-year average of 8.5 Bcf/d for the remainder of the refill season, the total inventory would be 3,543 Bcf on October 31, which is 176 Bcf lower than the five-year average of 3,719 Bcf for that time of year.
