U.S. natural gas prices likely to remain elevated through the winter:
In our October Short-Term Energy Outlook (STEO), we forecast that natural gas spot prices at the U.S. benchmark Henry Hub will average $5.67 per million British thermal units (MMBtu) between October 2021 and March 2021, the highest winter price since 2007–08. The increase in Henry Hub prices in recent months and in our forecast reflects below-average storage levels heading into the winter heating season and strong demand for U.S. liquefied natural gas (LNG), even though we’ve seen relatively slow growth in U.S. natural gas production. We expect Henry Hub prices will decrease early next year, as production growth outpaces growth in LNG exports, and will average $4.01/MMBtu in 2022. U.S. exports of LNG are on track to establish a record high this year, and we expect them to set a new record high next year. We expect LNG exports to average 9.7 billion cubic feet per day (Bcf/d) this year (3.2 Bcf/d more than the 2020 record high of 6.5 Bcf/d) and to exceed annual pipeline exports of natural gas for the first time. The year-on-year increase in LNG exports coincides with modest growth in U.S. natural gas production. We expect U.S. dry natural gas production to average 92.6 Bcf/d this year, which is 1.1 Bcf/d more than in 2020 but 0.3 Bcf/d less than in 2019. Because U.S. LNG exports have grown faster than domestic natural gas production, inventories are lower than average. As of the end of September, we estimate that U.S. natural gas inventories are 5.5% below the five-year (2016–2020) averages for this time of year. We forecast that U.S. inventories of natural gas will begin the winter heating season on November 1 at 3,572 Bcf, or 4.8% below the five-year average. Lower U.S. inventories could contribute to more natural gas price volatility, particularly if any area in the United States experiences a severe cold snap, which makes the price outlook for this winter very uncertain. In the second quarter of 2022, we forecast decreasing Henry Hub natural gas prices as anticipated growth in domestic natural gas production begins to outpace growth in U.S. LNG exports. We expect U.S. production to average 96.4 Bcf/d in 2022, or 3.9 Bcf/d more than in 2021, and U.S. LNG exports to rise by 1.4 Bcf/d during this time period to reach 11.2 Bcf/d. We forecast that faster growth in production will put downward pressure on natural gas prices.
Natural gas spot prices fell at most locations this report week (Wednesday, October 6 to Wednesday, October 13). The Henry Hub spot price fell from $5.95 per million British thermal units (MMBtu) last Wednesday to $5.45/MMBtu yesterday. International natural gas prices were mixed this report week. Bloomberg Finance, L.P. reports that swap prices for November liquefied natural gas (LNG) cargos in East Asia rose for the seventh week in a row to a weekly average of $33.24/MMBtu this report week, the highest weekly average on record since January 2020 and 76¢/MMBtu above last week’s average of $32.48/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, day-ahead prices declined for the first week since late August to a weekly average of $29.40/MMBtu this report week, down $2.88/MMBtu from last week’s average of $32.28/MMBtu. In the same week last year (week ending October 14, 2020), prices in East Asia and at TTF were $5.14/MMBtu and $4.73/MMBtu, respectively. The price of the November 2021 NYMEX contract decreased 9¢, from $5.675/MMBtu last Wednesday to $5.590/MMBtu yesterday after falling to a weekly low of $5.345/MMBtu on Monday. The January-delivery contract remains the highest on the 12-month strip, and it settled at $5.854/MMBtu yesterday, 3¢/MMBtu lower than last Wednesday at $5.888/MMBtu. The price of the 12-month strip averaging November 2021 through October 2022 futures contracts climbed 6¢/MMBtu to $4.724/MMBtu. All contracts for winter 2021–22 delivery settled lower this report week, but all contracts for delivery from April through October settled higher. The net injections to working gas totaled 81 billion cubic feet (Bcf) for the week ending October 8. Working natural gas stocks totaled 3,369 Bcf, which is 13% lower than the year-ago level and 5% lower than the five-year (2016–2020) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 2¢/MMBtu, averaging $12.38/MMBtu for the week ending October 13. The ethane price fell 1%, which is less than the 7% decrease in the natural gas price at the Houston Ship Channel for the same period. The ethane premium over natural gas increased by 32%, or 32¢/MMBtu, over the past week. Ethylene prices fell 8%, narrowing the margin between ethane and ethylene. Natural gasoline prices rose 3% following the 3% increase in Brent crude oil prices, while the prices of normal butane and isobutane remained relatively unchanged. Propane prices fell 3%, reflecting a relatively mild start to the winter heating season. The propane premium to crude oil narrowed for the first time since the end of August, by 33%, to just under $1.70/MMBtu for the week ending October 13. According to Baker Hughes, for the week ending Tuesday, October 5, the natural gas rig count remained flat at 99 rigs for the second week in a row. On a regional level, the rig count in the Utica fell by one this report week, offset by a one-rig gain in the Marcellus. The number of oil-directed rigs rose by 5 to 433, the most since mid-April 2020. The biggest gains in oil-directed drilling were in Texas, where the rig count rose by four, with a three-rig gain in the Permian and a one-rig gain in the Eagle Ford. The total rig count increased by 5, and it now stands at 533.
Natural gas prices decline in Southern Louisiana, but by less than in other markets, as a result of lower supply. This report week (Wednesday, October 6 to Wednesday, October 13), the Henry Hub spot price fell 50¢ from a weekly high of $5.95/MMBtu last Wednesday to $5.45/MMBtu yesterday, after declining to a weekly low of $5.36/MMBtu on Tuesday. The natural gas market in Southern Louisiana, where the Henry Hub is located, tightened this report week. IHS Markit estimates average net flows into Southern Louisiana declined by more than 0.4 Bcf/d week over week as a result of less natural gas flowing from the north. Demand in the region remained relatively flat, averaging 12.2 Bcf/d, which is less than 0.1 Bcf/d below the previous report week. Midwest prices fall in line with price declines in other major markets. At the Chicago Citygate, the price decreased 57¢ from $5.75/MMBtu last Wednesday to $5.18/MMBtu yesterday. Prices at the Chicago Citygate reached a weekly low of $5.08/MMBtu on Monday. Demand in the Midcontinent shifted from cooling to heating this report week, reflecting an average 200 million cubic feet per day (MMcf/d) drop in natural gas consumption for power generation this report week. This drop was offset somewhat by a 140 MMcf/d rise in natural gas consumption in the residential and commercial sector, as reported by IHS Markit. Temperatures in Chicago fell week over week from an average of 66°F last Wednesday, which resulted in zero heating degree days (HHD—a measure of heating demand), to an average of 62°F yesterday, which resulted in three HDDs. Temperatures in the Midwest remain above normal, however. Under a normal weather scenario, Chicago would have had 10 HDDs yesterday, based on an average daily temperature of 55°F. Prices in the West decrease as cooler temperatures lower consumption for natural gas in the electric power sector. The price at the PG&E Citygate in Northern California fell 36¢, which is down from $7.22/MMBtu last Wednesday to $6.86/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, fell 52¢ from $6.10/MMBtu last Wednesday to $5.58/MMBtu yesterday. Prices at the PG&E Citygate and Malin remain elevated as a result of higher prices further upstream. Prices at Sumas, the main delivery point of natural gas into the Pacific Northwest from Western Canada on the Washington State/British Columbia border, rose 52¢ from $6.03/MMBtu last Wednesday to $6.55/MMBtu yesterday. This report week, Sumas is one of the few pricing points in North America with prices higher yesterday than last Wednesday. This price increase was primarily the result of pipeline congestion on the West Coast pipeline that moves natural gas from the northeastern British Colombia production region to major consumption regions around Vancouver, Canada, and into the Pacific Northwest via an interconnect with Northwest Pipeline at the Sumas border crossing. Enbridge, operator of the Westcoast pipeline, reports curtailments on the pipeline’s southbound Station 4B compressor, which is currently operating at approximately 1.2 MMcf/d (Notice ID 55113), compared with flows above 1.5 Bcf/d (Notice ID 55077) prior to recent curtailments. According to data from IHS Markit, consumption of natural gas for electric power generation throughout the West declined this week by 0.7 Bcf/d, or 15%. Temperatures were below normal for the entire region, decreasing cooling demand. IHS Markit estimates natural gas consumption in the Desert Southwest declined by more than 0.2 Bcf/d week over week as a result of reduced natural gas consumption for power generation, resulting in lower prices in the region and in lower flows from West Texas and the Rockies. The price at the El Paso South Mainline/North Baja pricing point, which reflects prices in Arizona and New Mexico, fell 57¢ this report week, from $6.23/MMBtu last Wednesday to $5.66/MMBtu yesterday. The reduced demand along the path of major pipelines from West Texas to Southern California had knock-on effects on prices in SoCalGas service territory. The price at SoCal Citygate in Southern California decreased 59¢ from $6.59/MMBtu last Wednesday to $6.00/MMBtu yesterday. LNG terminal maintenance concludes in the Northeast. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 36¢, from $5.21/MMBtu last Wednesday to $4.85/MMBtu yesterday. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 4¢ from $5.34/MMBtu last Wednesday to $5.30/MMBtu yesterday. The price at the Algonquin Citygate decreased to a weekly low of $4.66/MMBtu on Friday before increasing to $5.30/MMBtu yesterday. Prices in New England fell by less than prices in other markets on tighter natural gas market balances. IHS Markit estimates supply into New England declined on average by 130 MMcf/d this report week, while demand rose by 130 MMcf/d, led by increased consumption for power generation, which accounted for 100 MMcf/d of the increase. The rise in power demand was the result of above-normal temperatures and cooling demand during what would normally be the shoulder season. Temperatures in Boston averaged 69°F yesterday, more than 13°F above normal, resulting in four cooling degree days (CDD— a measure of air conditioning demand). Under a normal weather scenario, temperatures in Boston would result in heating demand and 10 HDDs. Maintenance at the Cove Point liquefaction terminal was completed on Tuesday, October 12 (notice ID 124956), increasing demand for natural gas in the Northeast region. Prior to the maintenance outage, Cove Point feed gas receipts averaged 756 MMcf/d. Pipeline maintenance impacts flows out of Appalachia, putting downward pressure on prices. The Tennessee Zone 4 Marcellus spot price decreased 39¢ from $5.06/MMBtu last Wednesday to $4.67/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell 34¢ from $5.10/MMBtu last Wednesday to $4.76/MMBtu yesterday. Planned maintenance on the NEXUS Gas Transmission pipeline (planned service outage, notice ID 113221) began this week, impacting flows of natural gas out of eastern Ohio. Reduced flows on the NEXUS pipeline, which delivers natural gas into a number of interstate natural gas pipelines in the Midwest, resulted in lower net flows of natural gas from the Midwest to Eastern Canada, which declined on average by 0.3 Bcf/d this report week. Prices in the Permian Basin decrease by more than the Henry Hub price. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 86¢/MMBtu this report week, from $5.58/MMBtu last Wednesday to $4.72/MMBtu yesterday. The Waha Hub traded 73¢/MMBtu below the Henry Hub price yesterday, compared with last Wednesday when it traded 37¢/MMBtu below the Henry Hub price. Prices in West Texas decreased to weekly lows on Monday, October 11, and then increased the following day. The Waha price decreased to a low of $3.94/MMBtu on Monday, before increasing to $4.92/MMBtu on Tuesday. The price of natural gas delivered into the Transwestern pipeline, which delivers natural gas into the Desert Southwest, decreased to a low of $4.00/MMBtu on Monday and then increased to $4.90/MMBtu on Tuesday (see discussion on the West above). U.S. supply of natural gas rises slightly this report week as a result of increased dry natural gas production. According to data from IHS Markit, the average U.S. supply of natural gas rose by 0.2% compared with the previous report week, from an average of 97.7 Bcf/d last week to an average of 97.8 Bcf/d this report week. Dry natural gas production grew by 0.4% (0.4 Bcf/d), while net imports from Canada declined by 4.6% (0.2 Bcf/d) compared with the previous report week. U.S. natural gas consumption increases week over week as a result of rising consumption in the residential/commercial sector and higher feed gas deliveries to LNG export terminals. Total U.S. consumption of natural gas rose by 1.3% (1.1 Bcf/d) compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 1.2% (0.4 Bcf/d) week over week, which was more than offset by increased consumption in the residential/commercial sector, which rose by 9.2% (0.9 Bcf/d) as a result of cooler nighttime temperatures, which fell below 65°F across much of the country. Industrial sector consumption remained unchanged, averaging 21.2 Bcf/d. Natural gas exports to Mexico increased 1.5% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 10.5 Bcf/d, or 0.5 Bcf/d higher than last week. U.S. LNG exports decrease week over week. Sixteen LNG vessels (six from Sabine Pass, four from Freeport, and three each from Cameron and Corpus Christi) with a combined LNG-carrying capacity of 58 Bcf departed the United States between October 7 and October 13, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Net injections into U.S. natural gas storage totaled 81 Bcf for the week ending October 8, compared with five-year (2016–2020) average net injections of 79 Bcf and last year’s net injections of 50 Bcf during the same week. Working natural gas stocks totaled 3,369 Bcf, which is 174 Bcf lower than the five-year average and 501 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 84 Bcf to 109 Bcf, with a median estimate of 91 Bcf. The average rate of injections into storage is 8% 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 7.7 Bcf/d for the remainder of the refill season, the total inventory would be 3,545 Bcf on October 31, which is 174 Bcf lower than the five-year average of 3,719 Bcf for that time of year.