In the News:
Hurricane Ida reduced U.S. natural gas production more than any other hurricane over the past ten years
Hurricane Ida, which made landfall on August 29, 2021, was the fifth-strongest recorded hurricane to make landfall in the continental United States. The hurricane caused more natural gas production shut-ins than any other hurricane in the past ten years, and the impacts of the late-August hurricane continue today. Hurricane Ida made landfall near Port Fourchon, Louisiana, as a Category 4 hurricane on the anniversary of 2005’s Hurricane Katrina. According to daily estimates from the U.S. Bureau of Safety and Environmental Enforcement (BSEE), Hurricane Ida reduced natural gas production in the Federal Offshore Gulf of Mexico by an estimated 38.4 billion cubic feet (Bcf) over 28 days, the most shut-in days reported by BSEE since 2012. At its peak of disruption, Ida shut in 2.1 billion cubic feet per day (Bcf/d) of Gulf of Mexico offshore production, of which approximately 0.2 Bcf/d remains impaired today, 60 days after Hurricane Ida made landfall.
At its peak, the disruption to offshore oil and natural gas activity caused by Hurricane Ida resulted in evacuating 288 production platforms and 11 drilling rigs. Fewer facilities were evacuated in advance of Hurricane Ida than for other recent hurricanes. For example, Hurricane Laura shut-in 299 platforms and 11 rigs, and Hurricane Isaac in 2012 shut-in 509 platforms and 50 rigs. However, the duration of the shut-ins caused by Hurricane Ida, more so than the number of evacuations, contributed to the larger reduction in natural gas production. For the 28 days during which BSEE reported shut-in natural gas volumes as a result of Hurricane Ida, impaired natural gas production totaled 38.4 Bcf, or 56.0% of total U.S. offshore natural gas production in a month (when compared with the monthly total production for January of the same year) and 1.2% of total U.S. natural gas production (when compared with the monthly production total in January of the same year). By comparison, Hurricanes Laura (2020) and Isaac (2012) shut in 18.2% and 20.0% of offshore natural gas production, respectively, and 0.5% and 1.3% of total U.S. natural gas production, respectively, when compared with the production total in January of the respective years.
Hurricane Ida's direct hit to Port Fourchon had a significant effect on day-to-day operations of Gulf of Mexico offshore oil and natural gas production and the ability of operators to recover after the hurricane. Over 250 companies that service offshore oil and natural gas production in the Gulf of Mexico have a stake in Port Fourchon. As a result of damage sustained during the storm, 63 offshore platforms remained unmanned for 14 days after the hurricane made landfall, or 11.3% of all platforms in the U.S. Gulf of Mexico. BSEE reported that 5.5% of platforms were still unmanned 25 days after the hurricane made landfall. BSEE ceased reporting the impacts of Hurricane Ida on September 23, 28 days after the hurricane started to impact production, when Gulf of Mexico offshore natural gas production was still more than 0.5 Bcf/d below pre-hurricane levels. By comparison, Hurricane Isaac resulted in the second-most days of impaired production when it took 17 days for offshore production to return to pre-hurricane levels.
The impact of Hurricane Ida continues to affect U.S. Gulf Coast natural gas supply today. Production from Shell Offshore’s West Delta-143 platform remains offline and is not expected to return until the first quarter of 2022. Shell's West Delta 143 transportation hub, which aggregates production from Shell Offshore-operated Mars and Ursa platforms, sustained significant damage, shutting in approximately 220 million cubic feet per day (MMcf/d) of natural gas production.
The Atlantic hurricane season ends November 30, but most hurricane activity takes place in August, September, and October. Hurricane Ida is the only 2021 storm that resulted in BSEE activating its hurricane response team to monitor evacuation and production statistics. Named storms have winds with maximum speeds above 39 miles per hour. As of October 28, there have been 20 named storms during the 2021 hurricane season. Although 2021 has had more named storms than the 30-year average computed by the National Oceanic and Atmospheric Administration (NOAA), 2021 still lags behind 2020, which had 30 named storms during the Atlantic hurricane season, and broke the previous record set in 2005.
Overview:
(For the week ending Wednesday, October 27, 2021)
- Natural gas spot prices rose at most locations this report week (Wednesday, October 20, to Wednesday, October 27). The Henry Hub spot price rose from $4.79 per million British thermal units (MMBtu) last Wednesday to $5.86/MMBtu yesterday.
- Increases in international natural gas prices slowed this report week. Bloomberg Finance, L.P. reports that swap prices for November liquefied natural gas (LNG) cargos in East Asia rose for the ninth week in a row to a weekly average of $34.05/MMBtu this report week, the highest weekly average on record since January 2020 (the first year for which comparable data are available) but less than price increases in previous weeks. The East Asia price rose 13 cents/MMBtu above last week’s average of $33.92/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, day-ahead prices fell this report week to a weekly average of $29.60/MMBtu, down 83 cents/MMBtu from last week’s average of $30.43/MMBtu. In the same week last year (week ending October 28, 2020), prices in East Asia and at TTF were $6.89/MMBtu and $5.17/MMBtu, respectively.
- The November 2021 NYMEX contract expired yesterday at $6.202/MMBtu, up $1.03/MMBtu from last Wednesday. The December 2021 NYMEX contract price increased to $6.198/MMBtu, up 75 cents/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging December 2021 through November 2022 futures contracts climbed 39 cents/MMBtu to $4.825/MMBtu. Futures contracts for natural gas for delivery in the winter months rose faster than futures contracts for natural gas for delivery during the coming summer. The average price of contracts for November through March delivery rose by 75.3 cents/MMBtu week over week to $6.117/MMBtu. The average price of contracts for delivery in April through September rose by 24.6 cents to $4.176/MMBtu.
- The natural gas plant liquids (NGPL) composite price at Mont Belvieu, Texas, fell by 32 cents/MMBtu, averaging $12.15/MMBtu for the week ending October 27, while average weekly Brent crude oil prices remained relatively unchanged this report week. Natural gasoline prices, which generally trend with crude oil prices, remained relatively unchanged. The decline in the NGPL composite price was primarily the result of a strong decline in propane prices, which fell 5% this report week as a result of lower-than-normal demand for this time in the winter heating season, and unseasonal inventory builds, which averaged close to 2 million barrels per week for two weeks in a row. Prices of butanes also fell. The weekly average price for normal butane fell 3% week over week and the price of isobutane fell 2%. Ethane prices remained relatively unchanged this report week, but prices of both natural gas at the Houston Ship Channel (HSC) and ethylene at the Mont Belvieu, Texas, hub rose. HSC natural gas rose to meet prices in other natural gas hubs, rising on average by 6.4% this report week. This increase resulted in a 19% reduction in the ethane-to-natural-gas premium, which fell to $1.23/MMBtu this report week. Ethylene prices rose 2% this report week, resulting in the ethylene-to-ethane margin increasing to 21 cents per pound, the highest average weekly margin in three weeks.
- According to Baker Hughes, for the week ending Tuesday, October 19, the natural gas rig count increased by 1 to 99. The number of oil-directed rigs fell by 2 to 443. Most changes in the rig count can be attributed to activity in Wyoming, where oil-directed rigs fell by four and natural gas-directed rigs rose by one. California and Louisiana also gained one oil-directed rig each. Louisiana’s offshore rig count is now at 12, just 2 less than pre-landfall preparations for Hurricane Ida, which reduced the Louisiana offshore rig count to zero. Utah and Texas lost one oil rig each, which was offset by a two-rig gain in New Mexico. The total rig count decreased by 1, and it now stands at 542.
Prices/Supply/Demand:
Natural gas prices along the Gulf Coast rise as a result of below-trend production in the region and a shift from cooling to heating demand across the country. This report week (Wednesday, October 20 to Wednesday, October 27), the Henry Hub spot price rose $1.07 from a weekly low of $4.79/MMBtu last Wednesday to a weekly high of $5.86/MMBtu yesterday. Production volumes from the Federal Offshore Gulf of Mexico (GOM) remain impaired. IHS Markit reports weekly average GOM flows to Southern Louisiana averaged less than 1.4 Bcf/d this report week, more than 0.2 Bcf/d below the 1.6 Bcf/d average in the seven days before shut-ins began to prepare for Hurricane Ida (see In the News). Nearly all impaired production can be attributed to the continuing outage on Shell’s West Delta-143 (WD-143) platform. Enbridge, operator of the Mississippi Canyon Gas Pipeline, reports the pipeline has received no natural gas from WD-143 since August 28, compared with more than 0.2 Bcf/d received on August 25, four days before Hurricane Ida made landfall. Natural gas demand rose in the Gulf Coast region as a result of higher natural gas flows into the Midcontinent region. IHS Markit reports weekly average natural gas demand in southern Louisiana fell by approximately 0.2 Bcf/d week over week, primarily as a result of lower feed gas deliveries to liquefied natural gas (LNG) export terminals, which were more than 0.2 Bcf/d lower than last week. However, feed gas deliveries rose near the end of the week, tightening the regional natural gas market. Cheniere, operator of the Creole Trail pipeline that delivers natural gas to the Sabine Pass LNG export terminal in Louisiana, reported natural gas deliveries to Sabine Pass rose from 1.0 Bcf/d last Wednesday to as high as 1.6 Bcf/d on Tuesday and close to 1.2 Bcf/d yesterday.
Prices in the Midwest rise as colder temperatures increase consumption of natural gas for space heating. At the Chicago Citygate, the price increased 99 cents from a weekly low of $4.83/MMBtu last Wednesday to a weekly high of $5.82/MMBtu yesterday. Consumption of natural gas in the residential and commercial sectors in the Midwest increased this week by 2.3 Bcf/d (78%), according to data from IHS Markit, as colder temperatures moved into the region. Temperatures in the Chicago area averaged 48.9ºF this week, resulting in 111 HDDs (heating degree days—a measure of heating demand) compared with 44 HDDs last week.
Prices in the West rise but by less than in other markets. The price at PG&E Citygate in Northern California rose 67 cents, up from $6.76/MMBtu last Wednesday to $7.43/MMBtu yesterday. Prices in Northern California rose by less than prices in markets closer to production areas. The price at Sumas on the Canada-Washington border, the main pricing point for natural gas into the Pacific Northwest, rose 99 cents from $5.08/MMBtu last Wednesday to $6.07/MMBtu yesterday. The price at Cheyenne Hub in southeast Wyoming rose $1.06 from $4.69/MMBtu last Wednesday to $5.75/MMBtu yesterday. Natural gas from both hubs reaches Malin, Oregon, the northern delivery point into PG&E service territory, where prices rose $1.03 from $5.01/MMBtu last Wednesday to $6.04/MMBtu yesterday. The natural gas supply/demand balance in the Pacific Northwest tightened as a result of higher natural gas flows out of the Rockies into the Desert Southwest. IHS Markit estimates flows from the Rockies production region to the Desert Southwest rose by more than 0.2 Bcf/d week over week in response to elevated prices in Southern California, while flows from the Rockies into the Pacific Northwest declined by 0.3 Bcf/d.
The strongest storm in more than 10 years caused widespread power outages in California, resulting in approximately 630,000 electric customers losing service in Pacific Gas and Electric (PG&E) service territory in Northern California. The storm, and the number of customers losing electric service, peaked on Sunday. In addition to strong winds, which peaked at more than 90 miles per hour in Almeda County, the storm brought a rapid shift in temperatures. Temperatures in Downtown Sacramento fell from an average of 67ºF on Thursday, October 21, which is approximately 3ºF above normal and resulted in 2 cooling degree days (CDD—a measure of air conditioning demand), to an average of 58ºF, which is approximately 6ºF below normal and resulted in 7 HDDs. As a result of the lower temperatures, and to some extent electricity outages in Northern California, demand for natural gas for power generation in California fell on Saturday and Sunday to an average of 1.6 Bcf/d for the two days from an average of 1.8 Bcf/d in the previous two days. This decline was offset by an increase in heating demand, which rose by 0.2 Bcf/d from approximately 1.5 Bcf/d in the first two days of this report week to 1.7 Bcf/d on Saturday and Sunday.
Downtown Sacramento experienced record-setting rainfall on Sunday. The National Oceanic and Atmospheric Administration (NOAA) reports 5.44 inches of rain fell on the city in a 24-hour period, breaking a record set in 1880. The rainfall resulted in a rapid rise in some hydroelectric reservoirs in California. Water levels in Lake Oroville, the second-largest reservoir in California, rose from 22% of capacity last Wednesday to 27% of capacity yesterday. The 644 MW Edward Hyatt Powerplant on Lake Oroville, which was shut down on August 5 due to low water levels, remains off-line as of today. Its lost capacity since August has mostly been replaced with additional natural gas generation.
The price at SoCal Citygate in Southern California increased 88 cents from $6.02/MMBtu last Wednesday to $6.90/MMBtu yesterday. Prices in Southern California remain elevated as a result of continuing maintenance on the El Paso Natural Gas pipeline (last week’s Prices/Supply/Demand section has more in-depth analysis).
This week’s Nor’easter results in extended power outages for consumers in the Northeast. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $1.13 from $4.52/MMBtu last Wednesday to $5.65/MMBtu yesterday, 1 cent below the weekly high of $5.66/MMBtu on Tuesday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased $1.29 from $4.15/MMBtu last Wednesday to $5.44/MMBtu yesterday after reaching a weekly high of $5.51/MMBtu on Tuesday. Consumption of natural gas in the residential and commercial sectors rose by 1.2 Bcf/d (29%) in the Northeast, according to data from IHS Markit. Temperatures in the Boston area averaged 56.1ºF this week, resulting in 62 HDDs compared with 28 HDDs last week.
A Nor’easter moved into the region early this week, decreasing consumption of natural gas in the electric power sector in the Northeast by an average 0.4 Bcf/d (6%) week over week according to data from IHS Markit. Power outages for over 400,000 customers were reported by the Massachusetts Emergency Management Agency yesterday as a result of the storm.
Prices in the Appalachia production region rise, following similar trends in prices across the country. The Tennessee Zone 4 Marcellus spot price increased $1.10 from $4.21/MMBtu last Wednesday to a weekly high of $5.31/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose $1.17 from $4.12/MMBtu last Wednesday to $5.29/MMBtu yesterday. The weekly high of $5.34/MMBtu reported for Eastern Gas South on Tuesday was the highest price at this location since February 17, when prices across the country rose to record highs as a result of major market disruptions caused by a severe winter storm on the Gulf Coast. Prices in the region rose despite pipeline maintenance that reduced capacity to ship natural gas out of the region into the Midwest. Planned maintenance on the Rockies Express Pipeline (REX) (notice ID 9149) at the Chandlersville and Washington Courthouse compressor stations in Ohio began on Tuesday, October, 26. These compressor stations move natural gas westward out of Ohio.
Prices in the Permian Basin increase less than most other pricing hubs. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 89 cents this report week, from $4.58/MMBtu last Wednesday to $5.47/MMBtu yesterday. The Waha Hub traded 39 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 21 cents below the Henry Hub price. Pipeline remediation on Line 1300 of the El Paso Natural Gas (EPNG) pipeline system that began last week, planned to end October 26, was completed a day early, on October 25, allowing pipeline flows west across New Mexico to increase by more than 0.2 Bcf/d. Line 2000, which transports gas across the Desert Southwest to the Ehrenberg delivery point into SoCal Gas service territory, continues to operate under reduced pressure. EPNG moves natural gas out of the Permian Basin region and into Southern California.
U.S. supply of natural gas this report week is up slightly as a result of increased dry natural gas production. According to data from IHS Markit, the average total supply of natural gas rose by 1.4% when compared with the previous report week’s total of 98.1Bcf /d. Nearly all of this increase was the result of dry natural gas production growing week over week by 1.5%, or 1.4 Bcf/d. Average net imports from Canada increased by 1.1% from last week to 5.8 Bcf/d, the highest weekly average since the third week of February 2021.
U.S. natural gas consumption increases week over week, led primarily by an increase in the residential/commercial sector. Total U.S. natural gas demand rose by 4.8% (4.1 Bcf/d) week over week, according to data from IHS Markit, which was more than twice the increase of the previous report week. Average weekly consumption of natural gas rose in all end-use sectors. The largest increase in demand was in the residential and commercial sector, which rose 24.3% (3.4 Bcf/d), as the country transitions into the winter heating season. Though temperatures are falling, the onset of the heating season has been delayed relative to normal weather. NOAA reports above-normal temperatures across much of the country this report week, except in the Great Lakes region and the West Coast. Natural gas consumed for power generation climbed by 2.0% (0.6 Bcf/d) week over week, and consumption in the industrial sector increased by 1.0% (0.2 Bcf/d) week over week. Natural gas exports to Mexico decreased 0.6%, and deliveries of feed gas to U.S. liquefied natural gas (LNG) export facilities averaged 10.6 Bcf/d, or 0.2 Bcf/d lower than last week.
U.S. LNG exports are flat week over week. Twenty LNG vessels (six from Sabine Pass, four each from Corpus Christi and Freeport, three from Cameron, two from Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 73 Bcf departed the United States between October 21 and October 27, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 87 Bcf for the week ending October 22, compared with the five-year (2016–2020) average net injections of 62 Bcf and last year's net injections of 32 Bcf during the same week. Working natural gas stocks totaled 3,548 Bcf, which is 126 Bcf lower than the five-year average and 403 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 76 Bcf to 94 Bcf, with a median estimate of 87 Bcf.
The average rate of injections into storage is 5% lower than the five-year average so far in this refill season (April through October). If the rate of injections into storage matched the five-year average of 5.0 Bcf/d for the remainder of the refill season, the total inventory would be 3,593 Bcf on October 31, which is 126 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:
Source: Graph created by the U.S. Energy Information Administration (EIA), based on data from Bureau of Safety and Environmental Enforcement (BSEE)Note: Only the top-five hurricanes in last ten years are included. Unreported weekend data from BSEE is assumed to equal next-report-date value.
Source: Graph created by the U.S. Energy Information Administration, based on data from Bureau of Safety and Environmental Enforcement (BSEE)
Note: Only the top-five hurricanes in last ten years are included. Unreported weekend data from BSEE is assumed to equal next-report-date value. Percentage of lost production calculated relative to same-year January total.
| Spot Prices ($/MMBtu) | Thu, 21-Oct |
Fri, 22-Oct |
Mon, 25-Oct |
Tue, 26-Oct |
Wed, 27-Oct |
|---|---|---|---|---|---|
| Henry Hub |
4.92 |
5.07 |
5.60 |
5.59 |
5.86 |
| New York |
4.56 |
4.48 |
5.44 |
5.51 |
5.44 |
| Chicago |
4.92 |
4.98 |
5.63 |
5.58 |
5.82 |
| Cal. Comp. Avg.* |
5.79 |
5.69 |
6.36 |
6.30 |
6.66 |
| Futures ($/MMBtu) | |||||
| November contract | 5.115 |
5.280 |
5.898 |
5.882 |
6.202 |
| December contract |
5.346 |
5.461 |
6.056 |
6.003 |
6.198 |
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Source: NGI's Daily Gas Price Index | |||||
| U.S. natural gas supply - Gas Week: (10/21/21 - 10/27/21) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 105.3 |
103.7 |
100.3 |
| Dry production | 93.6 |
92.2 |
89.3 |
| Net Canada imports | 5.8 |
5.8 |
4.1 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 99.5 |
98.1 |
93.5 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (10/21/21 - 10/27/21) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 67.5 |
63.3 |
68.6 |
| Power | 28.2 |
27.7 |
30.2 |
| Industrial | 21.9 |
21.7 |
22.4 |
| Residential/commercial | 17.4 |
14.0 |
16.1 |
| Mexico exports | 5.9 |
6.0 |
6.1 |
| Pipeline fuel use/losses | 6.4 |
6.2 |
6.2 |
| LNG pipeline receipts | 10.6 |
10.9 |
8.8 |
| Total demand | 90.4 |
86.3 |
89.8 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, October 19, 2021 |
Change from |
||
last week |
last year |
||
| Oil rigs | 443 |
-0.4% |
110.0% |
| Natural gas rigs | 99 |
1.0% |
35.6% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, October 19, 2021 |
Change from |
||
last week |
last year |
||
| Vertical | 28 |
-6.7% |
33.3% |
| Horizontal | 482 |
0.2% |
96.7% |
| Directional | 32 |
0.0% |
52.4% |
| Source: Chart by the U.S. Energy Information Administration (EIA), based on data from Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2021-10-22 |
2021-10-15 |
change |
|
| East | 885 |
862 |
23 |
|
| Midwest | 1,052 |
1,027 |
25 |
|
| Mountain | 212 |
211 |
1 |
|
| Pacific | 255 |
253 |
2 |
|
| South Central | 1,144 |
1,108 |
36 |
|
| Total | 3,548 |
3,461 |
87 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (10/22/20) |
5-year average (2016-2020) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 938 |
-5.7 |
906 |
-2.3 |
|
| Midwest | 1,116 |
-5.7 |
1,070 |
-1.7 |
|
| Mountain | 245 |
-13.5 |
221 |
-4.1 |
|
| Pacific | 323 |
-21.1 |
305 |
-16.4 |
|
| South Central | 1,329 |
-13.9 |
1,173 |
-2.5 |
|
| Total | 3,951 |
-10.2 |
3,674 |
-3.4 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Oct 21) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 50 |
-56 |
-33 |
1 |
1 |
1 |
||
| Middle Atlantic | 43 |
-53 |
-29 |
5 |
4 |
5 |
||
| E N Central | 64 |
-38 |
-50 |
1 |
0 |
1 |
||
| W N Central | 83 |
-17 |
-59 |
0 |
-1 |
0 |
||
| South Atlantic | 33 |
-20 |
-7 |
31 |
7 |
1 |
||
| E S Central | 39 |
-14 |
-6 |
11 |
2 |
5 |
||
| W S Central | 21 |
0 |
4 |
31 |
5 |
-10 |
||
| Mountain | 101 |
5 |
25 |
5 |
-5 |
-17 |
||
| Pacific | 47 |
9 |
36 |
2 |
-4 |
-35 |
||
| United States | 53 |
-21 |
-15 |
12 |
2 |
-6 |
||
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from the National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Oct 21, 2021
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Oct 21, 2021
Source: National Oceanic and Atmospheric Administration
