Natural Gas

Overview:

(For the week ending Wednesday, September 8, 2021)

• Natural gas spot prices rose at most locations this report week (Wednesday, September 1 to Wednesday, September 8). The Henry Hub spot price rose from $4.46 per million British thermal units (MMBtu) last Wednesday to $4.78/MMBtu yesterday
• The price of the October 2021 NYMEX contract increased 30¢, from $4.615/MMBtu last Wednesday to $4.914/MMBtu yesterday. This was the highest close for a NYMEX futures front-month contract since late February 2014, when the U.S. Midwest was affected by multiple polar vortices. The price of the 12-month strip averaging October 2021 through September 2022 futures contracts climbed 25¢/MMBtu to $4.315/MMBtu. The average includes futures contracts for December 2021 and January 2022 delivery, which both closed above $5.00/MMBtu yesterday.
• The net injections to working gas totaled 52 billion cubic feet (Bcf) for the week ending September 3. Working natural gas stocks totaled 2,923 Bcf, which is 17% lower than the year-ago level and 7% lower than the five-year (2016–2020) average for this week.
• The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 49¢/MMBtu, averaging $10.33/MMBtu for the week ending September 8. Natural gasoline prices rose 1%, while isobutane prices rose 3%, following the 2% increase in Brent crude oil prices. Propane and normal butane prices increased by 5% and 6%, respectively, as exports of liquefied petroleum gas (LPG—propane, normal butane, and isobutane) remained elevated. The propane premium over crude oil, on a heat-content equivalent basis ($/MMBtu), widened for the week ending September 8, increasing 59% from the previous week. The propane premium to crude oil is now higher than it was three weeks ago. Ethane prices rose 9%, less than the 12% increase in natural gas prices on the Houston Ship Channel, reducing the ethane premium to natural gas by 7% for the week ending September 8. We estimate up to 257,000 b/d of ethane-fed petrochemical cracking capacity was taken offline following Hurricane Ida. Some of this capacity is gradually returning, such as the ExxonMobil refining and petrochemical complex at Baton Rouge, Louisiana, but no dates have been set for return to operations of many other facilities in the path of the hurricane.
• According to Baker Hughes, for the week ending Tuesday, August 31, the natural gas rig count increased by 5 to 102. Natural gas rigs rose most in the Haynesville shale play, which gained 3 rigs. The number of oil-directed rigs fell by 16 to 394. Oil-directed rig declines were led by Louisiana, where all 14 offshore rigs were taken offline as a result of industry preparations for Hurricane Ida. The Woodford and Granite Wash plays also lost rigs, at 2 and 1, respectively. The Permian Basin in New Mexico gained 1 rig to end the week at 79, the highest total since mid-April 2020. The total rig count decreased by 11, and it now stands at 497.

more summary data

Prices/Supply/Demand:

Tightening natural gas market supply-demand fundamentals result in prices at the Henry Hub rising for the third week in a row. This report week (Wednesday, September 1 to Wednesday, September 8), the Henry Hub spot price rose 32¢ from $4.46/MMBtu last Wednesday to a weekly high of $4.78/MMBtu yesterday. The Henry Hub spot price yesterday was more than 105% above the Henry Hub price on the same day last year, and the highest September spot price since September 2008, when Hurricane Ike affected offshore production in the Gulf of Mexico.

Supply disruptions following late August’s Hurricane Ida continue to affect supply of natural gas along the U.S. Gulf Coast. According to the Bureau of Safety and Environmental Enforcement (BSEE), as of 10:30 EDT today, 1.7 Bcf/d of natural gas production from the Gulf of Mexico offshore remains shut in 10 days after Hurricane Ida made landfall, and 71 offshore platforms remain unmanned. Overflight imagery from National Oceanic and Atmospheric Administration (NOAA) showing Port Fourchon and other locations along the Gulf Coast reveals extensive damage to energy-production-related infrastructure, including support facilities and natural gas processing plants. IHS Markit estimates on average 0.6 Bcf/d of natural gas production was received from the Gulf of Mexico offshore into interstate pipelines, compared with an average of 2.6 Bcf/d in the week preceding the hurricane. Enbridge, operator of the Mississippi Canyon Gas Pipeline, which serves offshore production, reports (Notice ID 111883) no deliveries on its pipeline as a result of a continuing outage at the 750 MMcf/d Venice Gas Plant near Sulfur, Louisiana. Entergy, the main electric utility in Louisiana, projects restoration of grid power by no later than September 29 across most southern Parishes. According to our EIA-757 survey, some of the largest natural gas plants serving Gulf of Mexico offshore production are located in the impacted Parishes, including the Venice Gas Plant in Plaquemines Parish and the 600 MMcf/d Larose Gas Plant in Lafourche Parish, which is also currently inactive according to IHS Markit pipeline flow data. CLECO, the electric utility serving parishes to the east and west of the Mississippi delta, reports power restored to over 90% of its customers, including only two outages in St. Mary Parish, where the 650 MMcf/d Neptune gas processing plant is located. IHS Markit reports flows through the natural gas plant restarted September 4, but flows remain depressed relative to pre-outage levels.

Natural gas prices rise throughout the Midwest despite relatively cool temperatures and reduced electricity demand for air conditioning. At the Chicago Citygate, the price increased 37¢ from $4.40/MMBtu last Wednesday to a weekly high of $4.77/MMBtu yesterday. Prices at Oneok Gas Transmission (OGT) receipt point in Oklahoma rose 26¢ from $4.36/MMBtu last Wednesday to a weekly high of $4.62/MMBtu yesterday. Natural gas prices in areas managed by Southwest Power Pool (SPP), which stretches from the Dakotas south to Oklahoma, were sufficiently high to depress natural gas consumption for power generation in the Midcontinent region, which according to IHS Markit declined by an average 2.0 Bcf/d week over week, in favor of higher coal-fired power plant utilization.

Prices in California rise, reflecting a general increase in North American natural gas prices and supply constraints. The price at PG&E Citygate in Northern California rose 81¢, up from $5.83/MMBtu last Wednesday to a weekly high of $6.64/MMBtu yesterday. Prices at hubs where Northern California sources its gas rose week over week in response to the rise in the Henry Hub price, which sets the trend for many North American natural gas hubs. The price at Sumas on the Canada-Washington border rose 60¢ from $4.40/MMBtu last Wednesday to $5.00/MMBtu yesterday. The price at Opal Hub in southwest Wyoming rose 68¢ from $4.40/MMBtu last Wednesday to $5.08/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, rose 75¢ from $4.41/MMBtu last Wednesday to $5.16/MMBtu yesterday. Prices at Sumas, Opal, and Malin all reached weekly highs on Tuesday, a day ahead of PG&E, at $5.14/MMBtu, $5.26/MMBtu, and $5.18, respectively.

The price at SoCal Citygate in Southern California increased $14.60 from $5.46/MMBtu last Wednesday to a weekly high of $20.06/MMBtu yesterday, the highest level since mid-February when a winter storm across the U.S. South resulted in power outages and well freeze-offs in Texas. The Southern California natural gas market is currently under-supplied, as a result of a continuing outage on the El Paso Gas Transmission (EPGT) pipeline and a heat wave that swept through the region over the Labor Day weekend. On expectations of significant increase in demand during the heat wave, SoCal Gas issued an advisory notice on September 2 urging customers to reduce consumption and be on the watch for supply curtailments. NOAA reports temperatures in the Riverside Area inland from Los Angeles reached a high of 107°F on Sunday, 13°F above normal, and remained above normal through the remainder of the report week, resulting in strong growth in natural gas consumption for power generation. IHS Markit reports power burn in California rose from a low of close to 1.9 Bcf/d at the start of the report week on Thursday to a high of more than 3.0 Bcf/d yesterday.

Prices in the Northeast rise along with higher temperatures at the end of the report week. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 52¢ from $3.97/MMBtu last Wednesday to $4.49/MMBtu yesterday. At the Transcontinental Pipeline (Transco) Zone 6 trading point for New York City, the price increased 50¢ from $3.86/MMBtu last Wednesday to $4.36/MMBtu yesterday. Prices in the region initially fell, reaching weekly lows at both the Algonquin Citygate and Transco Zone 6 on Friday, at $3.43/MMBtu and $3.38/MMBtu, respectively. Prices at both pricing points rebounded on Tuesday, following a long weekend that ended significantly warmer than expected. NOAA reports temperatures in the Boston area rose from a high of 74°F on Sunday (3°F below normal) to a high of 84°F on Monday (8°F above normal), driving Northeast natural gas consumption for electricity generation up by 10% day over day, from about 7.2 Bcf/d on Sunday to 7.9 Bcf/d on Monday, according to IHS Markit. Natural gas-fueled power generation in the region has continued to rise, reaching close to 9.0 Bcf/d yesterday.

Strong demand for natural gas in the Appalachian Basin results in rising prices. The Tennessee Zone 4 Marcellus spot price increased 31¢ from $3.82/MMBtu last Wednesday to $4.13/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 33¢ from $3.84/MMBtu last Wednesday to $4.17/MMBtu yesterday. Prices at both the Tennessee Zone 4 Marcellus and the Eastern Gas South trading hubs reached their highest levels yesterday, after falling to the lowest levels of the week on Friday, at $3.23/MMBtu and $3.47/MMBtu, respectively. Continuing curtailments to Gulf Coast production (see Henry Hub section above) have resulted in rising southbound natural gas flows out of the Appalachian production region. After rising on average 0.4 Bcf/d in the previous report week, southbound flows rose another 1.1 Bcf/d this report week, averaging slightly less than 8.0 Bcf/d, the second-highest weekly average level since the region became a net shipper of southbound natural gas in 2015.

Permian Basin prices rise in line with Gulf Coast natural gas prices. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 33¢/MMBtu this report week, from $4.30/MMBtu last Wednesday to $4.63/MMBtu yesterday. The discount between the Waha Hub and the Henry Hub on the Gulf Coast has remained relatively flat week over week, declining by 1¢/MMBtu. The Waha Hub traded 15¢/MMBtu below the Henry Hub price yesterday, compared with last Wednesday when it traded 16¢/MMBtu below the Henry Hub price.

Supply of natural gas falls this report week, led by production declines in Texas. According to data from IHS Markit, the average total supply of natural gas fell by 1.1% compared with the previous report week. Dry natural gas production decreased by more than 0.5 Bcf/d, or 0.6% compared with the previous report week, led by declines in North Texas production, which declined on average 0.3 Bcf/d week over week. Average net imports from Canada decreased by 11.0% from last week, as flows from Eastern Canada to the Midwest reversed course, from more than 0.1 Bcf/d flowing south into the United States to more than 0.2 Bcf/d flowing north into Canada.

U.S. natural gas demand falls week over week on reduced demand for power generation. Total U.S. consumption of natural gas fell by 9.4% compared with the previous report week, according to data from IHS Markit. The decline in natural gas consumed for power generation, which fell by more than 6.0 Bcf/d week over week, accounted for almost all of the total decline in domestic consumption. Consumption in the residential and commercial sector also declined, falling 0.5 Bcf/d, or 5.7%, week over week. Exports moved in opposite directions, as pipeline exports to Mexico declined week over week by 0.4 Bcf/d, or 6.8%, while pipeline deliveries to LNG export terminals increased by 0.4 Bcf/d, or 3.8%, week over week, reaching 10.9 Bcf/d.

U.S. LNG exports increase week over week. Twenty LNG vessels (seven from Sabine Pass, four each from Cameron, Corpus Christi, and Freeport, and one from Cove Point) with a combined LNG-carrying capacity of 74 Bcf departed the United States between September 1 and September 8, 2021, according to shipping data provided by Bloomberg Finance, L.P.

Storage:

The net injections into storage totaled 52 Bcf for the week ending September 3, compared with the five-year (2016–2020) average net injections of 65 Bcf and last year's net injections of 65 Bcf during the same week. Working natural gas stocks totaled 2,923 Bcf, which is 235 Bcf lower than the five-year average and 592 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 58 Bcf, with a median estimate of 42 Bcf.

The average rate of injections into storage is 15% 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 9.7 Bcf/d for the remainder of the refill season, the total inventory would be 3,484 Bcf on October 31, which is 235 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