Working gas stocks end refill season 3% below the five-year average:
Working natural gas in storage in the Lower 48 states totaled 3,613 billion cubic feet (Bcf) as of October 31—traditionally considered the end of the natural gas refill season (April 1–October 31), although injections sometimes extend into November. Total inventories as of October 31 were 102 Bcf (3%) less than the five-year (2016–2020) average and 284 Bcf (7%) less than total inventories last year at this time. Working natural gas stocks at the start of the 2021 refill season were 1,777 Bcf, 26 Bcf (1%) below the five-year average despite starting winter 2020/21 with working gas stocks of 3,897 Bcf, the fourth highest pre-winter stocks level on record. A late-season cold snap contributed to record-high spot natural gas prices and a sharp reduction in natural gas production that resulted in sizable withdrawals from storage. We estimate that net injections into storage totaled 1,836 Bcf during the refill season, 76 Bcf (4%) less than the five-year average and 56 Bcf (3%) less than last year’s refill season. Net injections into storage were lower than injection levels a year ago as a result of demand growth outpacing the growth in natural gas supply during the injection season. Total natural gas demand grew by about 6% this refill season, while total natural gas supply, comprising Lower 48 states’ dry gas production, net imports from Canada, and liquefied natural gas (LNG) sendout, increased by about 5%, according to IHS Markit data. Demand growth was spurred by a significant increase in U.S. LNG exports, which averaged 9.7 billion cubic feet per day (Bcf/d) this April through October, 4.7 Bcf/d higher than last year during that period. In contrast, LNG cargo cancellations and storm-related disruptions during the summer of 2020 freed up more natural gas for storage injections. Large differences between the price of natural gas in the United States compared with prices in Europe, South America, and Asia prompted increasing U.S. LNG in exports 2021 in response to tight global LNG supplies, global economic recovery, and summer natural gas stock refill needs in major overseas markets. U.S. natural gas exports to Mexico, which rose 11% during this year’s refill season compared with last year’s refill season, also contributed to higher demand for natural gas. In June 2021, the United States set a new record for monthly exports to Mexico. Natural gas use for power generation averaged 33 Bcf/d from April through October 2021, 3% lower compared with last year’s refill season, even though spot natural gas prices at the Henry Hub were almost $2 per million British thermal units (MMBtu) higher than last year. Several factors contributed to robust power burn amid higher natural gas prices: lower hydroelectric availability, typical shoulder season (fall and spring) maintenance for non-natural gas generators, episodic warmer-than-normal temperatures, diminished coal stocks, and structural coal generator retirements. Pacific Gas & Electric’s (PG&E) reclassification of 51 Bcf of working gas to base gas in June was another key factor reducing summer stocks. This non-flow change accounted for the 46 Bcf deficit to the five-year average reported in the Pacific region for the week ending November 5, 2021, and about 40% of the deficit to the Lower 48 states’ five-year average for the same week.
Natural gas spot prices rose at most locations this report week (Wednesday, November 10 to Wednesday, November 17). The Henry Hub spot price rose from $4.58 per million British thermal units (MMBtu) last Wednesday to $4.79/MMBtu yesterday. International natural gas prices rose this report week. Bloomberg Finance, L.P. reports that swap prices for liquefied natural gas (LNG) cargos in East Asia for the balance of the month (November) increased for the second week in a row. The weekly average rose to $32.69/MMBtu this report week, 55 cents/MMBtu above last week’s average of $32.13/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead price rose for the second week in a row to a weekly average of $27.68/MMBtu, up $2.95/MMBtu from last week’s average of $24.73/MMBtu. In the same week last year (week ending November 18, 2020), prices in East Asia and at TTF were $6.80/MMBtu and $4.74/MMBtu, respectively. The price of the December 2021 NYMEX contract decreased 6.4 cents, from $4.880/MMBtu last Wednesday to $4.816/MMBtu yesterday. The price of the 12-month strip averaging December 2021 through November 2022 futures contracts remained relatively unchanged Wednesday to Wednesday at $4.256/MMBtu; however, the futures curve continues to flatten. Futures for the balance of the winter months’ delivery declined 4.0 cents/MMBtu, whereas futures for summer months’ delivery rose 2.1 cents/MMBtu. Net injections to working gas totaled 26 billion cubic feet (Bcf) for the week ending November 12. Working natural gas stocks totaled 3,644 Bcf, which is 8% lower than the year-ago level and 2% lower than the five-year (2016–2020) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 89 cents/MMBtu, averaging $11.01/MMBtu for the week ending November 17. Ethane prices fell 5%, which is less than the 6% decrease in natural gas at the Houston Ship Channel. The ethane premium to natural gas rose 1%, while ethylene prices fell 3% for the week ending November 17. Propane prices fell 11% and are again at a discount to the Brent crude oil price for the first time since August, as a result of lower-than-average inventory draws for this time of year. Wholesale propane inventories declined by less than 200,000 barrels last week, compared with a 5-year average draw of almost 1.4 million barrels. Similar to propane, normal butane and isobutane prices fell 9% and 8%, respectively. Natural gasoline prices fell 2% following the 1% drop in Brent crude oil prices. According to Baker Hughes, for the week ending Tuesday, November 9, the natural gas rig count increased by 2 to 102. The net gain of two rigs was the result of a one-rig gain in the Permian Basin and a two-rig gain in the Utica, offset by a one-rig loss in an unidentified basin. The natural gas-directed rig count was last above 100 in the second week of September. The number of oil-directed rigs rose by 4 to 454. The total rig count now stands at 556. Oil-directed rigs and total rigs are now at the highest levels since mid-April 2020.
Gulf Coast prices rise but not as much as prices in other regions. This report week (Wednesday, November 10 to Wednesday, November 17), the Henry Hub spot price rose 21 cents from $4.58/MMBtu last Wednesday to $4.79/MMBtu yesterday. The price at the Henry Hub rose as high as $5.06/MMBtu on Tuesday. Production from Shell-operated Mars and Ursa platforms, which were curtailed as a result of damage sustained from Hurricane Ida, has been restored. Enbridge, operator of the Mississippi Canyon Gas Pipeline that serves offshore production from Shell’s Olympus, Mars, and Ursa platforms, reports natural gas volumes delivered to the Venice Gas Plant in Venice, Louisiana, increased by 70 million cubic feet per day (MMcf/d) on November 5 and an additional 100 MMcf/d on November 6. Current flows on the pipeline are approximately 230 MMcf/d, or more than 130 MMcf/d higher than before Shell’s November 5 announcement that production was restored at the two offshore platforms. Midwest prices rise as temperatures fall and heating demand rises. At the Chicago Citygate, the price increased 33 cents from $4.45/MMBtu last Wednesday to $4.78/MMBtu yesterday, after reaching a weekly high of $4.94/MMBtu on Tuesday. Temperatures in the Midwest fell rapidly this report week. In the Chicago Area the daily average fell from an average of 49°F (almost 6°F above normal) on Thursday to an average of 39°F (almost 4°F below normal) on Friday, and a weekly low of 33°F (more than 8°F below normal) on Monday. As a result, the National Oceanic and Atmospheric Administration (NOAA) reported 169 HDDs (heating degree days—a measure of heating demand) this report week, compared with 119 HDDs last week. IHS Markit estimates demand in the residential and commercial sectors rose by an average of 1.5 Bcf/d week over week to almost 5.7 Bcf/d, the highest weekly average since the third week of April. West Coast prices rise as a result of cooler weather in the north, warmer weather in the south, and supply disruptions due to flooding in British Columbia and Washington State. The price at Sumas on the Canada-Washington border rose $1.04 from $4.96/MMBtu last Tuesday (last Wednesday’s price is not available) to a weekly high of $6.00/MMBtu yesterday. Enbridge shut down (Notice ID 55212) one of two pipes in the Westcoast Energy system due to major flooding and mudslides in British Columbia, reducing natural gas supply to the City of Vancouver and the Huntington Delivery Area at the Sumas border crossing into Washington State. The outage is expected to last through Friday, but possibly longer, according to Westcoast Energy’s Critical Notice (Notice ID 55216). Williams, operator of the Northwest Pipeline that serves most of Washington and Oregon and indirectly delivers natural gas to the PG&E delivery point at Malin, Oregon, reports receipts of natural gas at Sumas on the British Columbia-Washington border declined by more than 370 MMcf/d, from 1,250 MMcf/d on Monday to 880 MMcf/d on Wednesday. The price at PG&E Citygate in Northern California rose 20 cents, up from $6.00/MMBtu last Wednesday to $6.20/MMBtu yesterday. Prices at PG&E Citygate dropped as low as $5.75/MMBtu on Friday before rising again as a result of supply concerns related to severe flooding in the Pacific Northwest. The price at SoCal Citygate in Southern California increased $1.19 from $5.55/MMBtu last Wednesday to a weekly high of $6.74/MMBtu yesterday, after falling as low as $5.09/MMBtu on Friday. Temperatures in the Riverside, California area, inland from Los Angeles, averaged 71°F this week, 9°F above normal for this time of year, resulting in 44 CDDs (cooling degree days—a measure of cooling demand) compared with 9 CDDs last week. The daily high in Riverside rose to 94°F on Sunday, just 1°F below the all-time high set in 1906. Natural gas consumption in the electric power sector was 5.0% higher in California this week, according to data from IHS Markit. Supply of natural gas into the SoCal Gas market area remains impeded. SoCal Gas issued critical notices of maintenance on the Aliso Canyon storage facility, identifying expected intermittent outages for flow testing to occur November 11 through 15, November 16 through 17, and November 18 through 21. This maintenance is in addition to ongoing maintenance at other SoCal Gas storage facilities where withdrawal rates are curtailed, including the Goleta field, where unplanned maintenance has reduced withdrawal capacity by more than 200 MMcf/d, and the Honor Rancho field, where planned maintenance, which began October 31, has reduced withdrawal capacity by more than 400 MMcf/d. SoCal Gas does not specify a completion date for either of the two maintenance outages. Flows into SoCal Gas territory also remain constrained. The El Paso Natural Gas Company released its December maintenance schedule, which shows Line 2000 will remain shut-in for all of December as it continues to undergo repairs following a rupture in August near Coolidge, Arizona. The pipeline outage has reduced flows into Southern California by approximately 610 MMcf/d. Northeast prices rise in response to lower temperatures and higher space heating demand. At the Algonquin Citygate, which serves Boston-area consumers, the price increased 42 cents from $4.14/MMBtu last Wednesday to $4.56/MMBtu yesterday. Prices at the Algonquin Citygate rose to a weekly high of $5.17/MMBtu on Friday in anticipation of rapidly cooling weather over the weekend. Boston area temperatures dropped from an average of 56°F on Friday, more than 10°F above normal, to a daily average of less than 44°F on Sunday, almost 2°F below normal. The increase in heating demand, reflected by the 128 HDDs reported by NOAA this week, compared with 119 HHDs last week, resulted in an increase in natural gas consumption in the residential and commercial sectors in New England, which rose on average 8.3% week over week, according to data from IHS Markit. Deliveries into the region also declined as a result of higher demand in upstream markets in Canada and the Mid-Atlantic as a result of the same cooling trend (see Midwest section above). At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 72 cents from $3.76/MMBtu last Wednesday to $4.48/MMBtu yesterday, after reaching a weekly high of $4.66/MMBtu on Tuesday. Temperatures and demand in the New York/New Jersey region followed a similar pattern as New England, though the cooling trend strengthened through Tuesday. NOAA reported temperatures in New York City’s Central Park averaged 58°F on Friday, almost 9°F above normal, and fell through the weekend to 43°F on Sunday and a weekly low of less than 43°F on Tuesday, more than 5°F below normal. Natural gas demand for space heating in the residential and commercial sectors rose through the report week by 6.7% above last week’s average. Consumption in the residential and commercial sector increased this report week, reflecting the rapid drop in temperatures from just above 1.7 Bcf/d on Friday (the lowest level since late October) to above 3.4 Bcf/d (the highest level since late April), according to IHS Markit estimates. Prices in the Appalachia production region rise in response to higher demand in the Midwest and Northeast and to the end of pipeline maintenance. The Tennessee (TGP) Zone 4 Marcellus spot price increased 64 cents from $3.63/MMBtu last Wednesday to $4.27/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 64 cents from $3.67/MMBtu last Wednesday to $4.31/MMBtu yesterday. Prices at both the TGP Zone 4 and Eastern Gas South hubs reached weekly highs on Tuesday at $4.41/MMBtu and $4.49/MMBtu, respectively. On Wednesday, Enbridge, the operator of the Texas Eastern Transmission Pipeline (TETCO), lifted a force majeure (Notice ID 114491) that had been in effect since October 1. This action allowed westbound capacity on the 26-inch diameter segment in Ohio between the Somerset compressor station in Somerset and the Five Points compressor station in Williamsport to rise by almost 400 MMcf/d. As a result of improved flows on the 26-inch diameter line, westbound flows on TETCO out of the Appalachia production region past the Holbrook compressor station rose from below 800 MMcf/d prior to the lifting of the force majeure to above 1 Bcf/d in the past three days. The discount in the Permian production basin relative to the Henry Hub falls as a result of lower production this report week. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 63 cents this report week, from $3.99/MMBtu last Wednesday to $4.62/MMBtu yesterday. The Waha Hub traded 17 cents/MMBtu below the Henry Hub price yesterday compared with last Wednesday, when it traded 59 cents/MMBtu below the Henry Hub price. IHS Markit estimates production in the Permian Basin fell by 0.4 Bcf/d this report week, led by declines in the New Mexico portion of the play, which declined by close to 0.3 Bcf/d. New pipeline between Eddy County in New Mexico and the Waha Hub in Texas to improve connectivity for Permian producers. Today, Summit Midstream announced that service has begun on the Double E pipeline, which will increase natural gas flows from the New Mexico portion of the Permian Basin south to the Waha Hub. The pipeline’s 1.35 Bcf/d of capacity is likely to alleviate congestion in the region and improve connectivity between producers in the northern Delaware Basin and a number of major pipelines out of the Waha Hub, resulting in higher dry gas production after this report week’s decline. U.S. supply of natural gas is down this report week as a result of decreasing dry natural gas production. According to data from IHS Markit, the average total supply of natural gas fell to 99.3 Bcf/d this report week, a 1.7% decrease from the previous report week’s total of 101.0 Bcf/d. Dry natural gas production decreased by 1.1% (1.1 Bcf/d) compared with the previous report week. Average net imports from Canada decreased by 11.6% (0.6 Bcf/d) from last week. Compared with last year, total supply is up 4.5% this report week from an average 95.1 Bcf/d in the same period a year ago. U.S. total natural gas consumption increases week over week, led primarily by the residential and commercial sector. Total U.S. consumption of natural gas rose by 3.0% (2.3 Bcf/d) compared with the previous report week, according to data from IHS Markit. The largest week-over-week increase was in the residential and commercial sector, where consumption increased by 11.8% (2.9 Bcf/d). NOAA reported average nighttime temperatures approached freezing across a large section of the North and Central United States and cool average daytime temperatures across the North Central and Southeast United States. Natural gas consumed for power generation declined by 3.0% (0.9 Bcf/d) week over week, and industrial sector consumption increased by 1.1% (0.2 Bcf/d) week over week. Natural gas exports to Mexico decreased 3.5% (0.2 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.1 Bcf/d, or about 0.1 Bcf/d lower than last week. Total demand is up 6.8% this report week compared with the same period a year ago. U.S. LNG exports have increased this week from last week. Twenty-two LNG vessels (seven from Sabine Pass, five from Corpus Christi, four each from Freeport and Cameron, and two from Cove Point (none from Elba Island)) with a combined LNG-carrying capacity of 79 Bcf departed the United States between November 11 and November 17, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Net injections into storage totaled 26 Bcf for the week ending November 12, compared with the five-year (2016–2020) average net withdrawals of 12 Bcf and last year’s net injections of 28 Bcf during the same week. Working natural gas stocks totaled 3,644 Bcf, which is 81 Bcf lower than the five-year average and 310 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 13 Bcf to 33 Bcf with a median estimate of 23 Bcf.