Natural Gas

Overview:

(For the week ending Wednesday, August 25, 2021)

• Natural gas spot prices rose at most locations this report week (Wednesday, August 18, to Wednesday, August 25). The Henry Hub spot price rose from $3.86 per million British thermal units (MMBtu) last Wednesday to $4.01/MMBtu yesterday.
• The price of the September 2021 NYMEX contract increased 4¢, from $3.852/MMBtu last Wednesday to $3.897/MMBtu yesterday. The price of the 12-month strip averaging September 2021 through August 2022 futures contracts climbed 4¢/MMBtu to $3.709/MMBtu.
• The net injections to working gas totaled 29 billion cubic feet (Bcf) for the week ending August 20. Working natural gas stocks totaled 2,851 Bcf, which is 16% lower than the year-ago level and 6% lower than the five-year (2016–2020) average for this week.
• The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 27¢/MMBtu, averaging $9.56/MMBtu for the week ending August 25. Normal butane and isobutane prices fell 4%. Natural gasoline prices decreased 2%, in line with a 2% drop in Brent crude oil prices. Propane prices, which reached record highs last week, also fell 2%. Although propane prices are still at a premium to crude oil prices, the price spread narrowed from 5% above Brent crude oil prices last week to 4% above Brent crude oil prices this week, measured on a heat-content equivalent ($/MMBtu). Ethane prices decreased 3%, more than the 1% decline in ethylene prices and the flat weekly average natural gas price at the Houston Ship Channel. Ethane prices declined for a second week in a row after reaching above $5/MMBtu two weeks ago—the highest level since February 2019. The ethane premium to natural gas narrowed by 12%, or $0.14/MMBtu, for the week ending August 25.
• According to Baker Hughes, for the week ending Tuesday, August 17, the natural gas rig count decreased by 5 rigs to 97 rigs, and it is now at its lowest level in over two months. Losses were distributed across various basins: Eagle Ford, Haynesville, and Marcellus all lost one rig, with minor changes in the “other regions” category. The number of oil-directed rigs rose for the third week in a row, by 8 rigs to 405 rigs. The Permian Basin gained three rigs: two in Texas and one in New Mexico. Three oil rigs were also added in Louisiana, and the other two rigs were in other regions. The total rig count increased by 3 rigs, and it now stands at 503 rigs, the highest level since mid-April 2020.

more summary data

Prices/Supply/Demand:

Henry Hub prices rise with increasing demand alongside increasing prices across the country. This report week (Wednesday, August 18, to Wednesday, August 25), the Henry Hub spot price rose 15¢ from $3.86/MMBtu last Wednesday to $4.01/MMBtu yesterday. Strong natural gas demand across the central and eastern United States, driven by above-normal temperatures and air-conditioning demand that led to increased power generation, increased prices in most markets, putting upward pressure on the Henry Hub price, which reached the highest level for this report week yesterday.

Prices rise across the Midwest as temperatures rise well above normal, driving power generation demand higher. At the Chicago Citygate, the price increased 23¢ from $3.72/MMBtu last Wednesday to a weekly high of $3.95/MMBtu yesterday. Temperatures in Chicago reached a weekly high of 96°F, a new historical high and 14°F above normal, on Tuesday and remained elevated yesterday, reaching a daily high of 94°F. Temperatures in other major cities in the Midwest also recorded well-above-normal temperatures yesterday. Des Moines, Iowa, reached a high of 93°F (10°F above normal); Kansas City, Kansas, reached 93°F (7°F above normal); and St. Louis, Missouri, at 100°F (13°F above normal), was just 1°F below the all time-high set in 1943. The resulting air-conditioning demand has driven power generation to record levels in some markets, increasing natural gas consumption for power generation in the Midwest to over 4.6 billion cubic feet per day (Bcf/d) yesterday according to IHS Markit, the highest level since the last week of June. On Tuesday and yesterday, the Midcontinent Independent System Operators (MISO), the electricity-balancing authority for much of the Midwest, issued an operational alert for maximum power generation resources due to the heatwave.

California prices rise in response to pipeline constraints, despite lower temperatures and reduced power generation demand. The price at the Pacific Gas and Electric Company (PG&E) Citygate in Northern California rose 4¢, up from $5.16/MMBtu last Wednesday to a weekly high of $5.20/MMBtu on Tuesday and yesterday. Gas Transmission Northwest (GTN), which receives natural gas imported from Canada at Kingsgate, Idaho, reduced flows on the pipeline by approximately 0.2 Bcf/d early in the report week due to maintenance, which was completed this morning (Notice ID 833). GTN moves natural gas across the Pacific Northwest, terminating at Malin, Oregon, the northern delivery point into the PG&E territory. Prices at Malin rose 7¢ from $4.17/MMBtu last Wednesday to $4.24/MMBtu yesterday, after reaching a weekly high of $4.50/MMBtu on Tuesday, the highest level since mid-February.

The price at SoCal Citygate in Southern California increased $1.97 from $4.77/MMBtu last Wednesday to $6.74/MMBtu yesterday. SoCal Citygate prices reached a weekly low of $4.14/MMBtu on Friday, reflecting relatively low demand as temperatures in the region fell below normal. In Riverside, inland from Los Angeles, where daily high temperatures for this time of year approach 100°F, the daily maximum temperature on Saturday reached 77°F, 18°F below normal and a new historical low for the day. IHS Markit estimates natural gas demand for power generation in California fell below 1.5 Bcf/d over the weekend, after averaging over 2.5 Bcf/d in the prior week. The lower demand coincided with reduced flows on the El Paso Natural Gas Company (EPNG) pipeline due to a force majeure covered in last week’s report. Following up on the initial announcement and reduction in flows, EPNG issued an updated critical notice (Notice ID 612712) that lists further delivery reductions due to reduced pressure on Line 2000, which moves natural gas from the Permian Basin in west Texas to the California border. Effective August 26, with no specified end date, EPNG will reduce deliverability of natural gas along the pipeline’s path to numerous delivery points, including a reduction of approximately 0.5 Bcf/d at Ehrenberg, the delivery point into Southern California. The reduction in available natural gas into the SoCal territory, as well as a return to above-normal temperatures, has resulted in SoCal prices reaching a weekly high yesterday.

Prices in the Northeast rise because of warmer weather and increased air-conditioning demand. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 44¢ from $3.88/MMBtu last Wednesday to $4.32/MMBtu yesterday, after reaching a weekly high of $4.43/MMBtu on Tuesday. At the Transcontinental Pipeline (Transco) Zone 6 trading point for New York City, the price increased 16¢ from $3.83/MMBtu last Wednesday to a weekly high of $3.99/MMBtu yesterday. Temperatures in the region rose rapidly through the week. Temperatures in Boston reached a high of 94°F yesterday, 15°F above normal and 6°F above last Wednesday’s high. Temperatures and prices in the Boston area reached a weekly low on Friday when the daily high fell to 79°F, 1°F below normal, and the price at the Algonquin Citygate fell to $3.87/MMBtu. New York weather and prices followed a similar pattern. The highest temperatures of the week were reported yesterday, when the daily high in Central Park reached 91°F, 9°F above normal, and fell to weekly lows on Friday, when the daily high was 82°F, 1°F below normal. Prices at Transco Zone 6 fell to a weekly low of $3.71/MMBtu on Thursday, and they remained nearly flat through Friday before rising again early this week.

Prices in the Appalachian production region rise, but not as much as in the demand regions, as pipeline capacity limits are reached. The Tennessee Zone 4 Marcellus spot price increased 13¢ from $3.55/MMBtu last Wednesday to $3.68/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 15¢ from $3.58/MMBtu last Wednesday to $3.73/MMBtu yesterday. Prices at both hubs reached their weekly highs yesterday. IHS Markit reports natural gas flows out of the region approached 26 Bcf/d yesterday, about 1 Bcf/d below the all-time highs reported in March.

Prices in the Permian Basin production region increase, despite reduction in pipeline takeaway capacity. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 17¢, from $3.51/MMBtu last Wednesday to $3.68/MMBtu yesterday. The discount at the Waha hub relative to the Henry Hub decreased by 2¢, from 35¢/MMBtu last Wednesday to 33¢/MMBtu yesterday. The discount at the Waha Hub relative to SoCal Citygate increased from $1.26/MMBtu last week to $3.06/MMBtu this week, as congestion on the EPNG pipeline resulted in a decline of approximately 0.5 Bcf/d in westbound natural gas shipments out of the Permian Basin, compared with pre-outage flows reported prior to August 15, the day Line 2000 ruptured in Arizona (see discussion in the California section above).

Average U.S. natural gas supply rises from all sources week over week. Total average supply of natural gas rose by 0.9%, or 0.9 Bcf/d, compared with the previous report week, according to data from IHS Markit. Average marketed natural gas production and average dry production rose 0.8% and 0.7% respectively (or 0.8 and 0.7 Bcf/d). Average net Canadian imports rose 3.7%, or 0.2 Bcf/d, and average sendout from LNG import terminals increased 2.7% this report week.

Average U.S. natural gas consumption increases compared with the previous report week due to higher demand for power generation. Average total U.S. consumption of natural gas rose by 0.8%, or 0.7 Bcf/d, week over week, driven by a 2.8%, or 1.0 Bcf/d, increase in power generation. Higher than average temperatures across the upper Midwest and the eastern portion of the United States contributed to increased electric power demand. Average weekly residential and commercial consumption remained relatively unchanged. Declining demand in the industrial sector and exports offset some of the growth. The average consumption in the industrial sector declined 0.5%, or 0.1 Bcf/d. Pipeline exports to Mexico fell 1.2%, or 0.1 Bcf/d, and pipeline deliveries to LNG export terminals declined by 2.6%, or 0.2 Bcf/d.

U.S. LNG exports increase week over week. Eighteen LNG vessels (six from Sabine Pass, four from Corpus Christi, three each from Cameron and Freeport, and one each from Cove Point and Elba Island), with a combined LNG-carrying capacity of 67 Bcf, departed the United States between August 19 and August 25, 2021, according to shipping data provided by Bloomberg Finance, L.P.

Storage:

The net injections into storage totaled 29 Bcf for the week ending August 20, compared with the five-year (2016–2020) average net injections of 44 Bcf and last year's net injections of 45 Bcf during the same week. Working natural gas stocks totaled 2,851 Bcf, which is 189 Bcf lower than the five-year average and 563 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 30 Bcf to 47 Bcf, with a median estimate of 38 Bcf.

The average rate of injections into storage is 13% 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 9.4 Bcf/d for the remainder of the refill season, the total inventory would be 3,530 Bcf on October 31, which is 189 Bcf lower than the five-year average of 3,719 Bcf for that time of year.

More storage data and analysis can be found on the Natural Gas Storage Dashboard and the Weekly Natural Gas Storage Report.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook