In the News:
EIA expects U.S. natural gas prices to average above $6.00/MMBtu this winter
In our November Short-Term Energy Outlook (STEO), we forecast that natural gas spot prices at the U.S. benchmark Henry Hub will average $6.09 per million British thermal units (MMBtu) this winter (November 2022–March 2023), the highest real price since winter 2009–10. Our forecast reflects natural gas storage levels that were 3% below the five-year (2017–21) average heading into the winter withdrawal season and increased demand for liquefied natural gas (LNG) as the Freeport LNG facility comes back online. After the winter, we expect the Henry Hub price to decline in 2023 as production growth outpaces both domestic consumption and LNG exports.
Average monthly Henry Hub natural gas spot prices in 2022 reached a peak of $8.80/MMBtu in August. Prices declined to an average of $5.66/MMBtu in October following several consecutive weeks of relatively large injections into underground natural gas storage throughout September and October as a result of strong dry natural gas production and above-normal temperatures, which lowered residential and commercial demand for space heating. From the end of August to the end of October, the storage deficit to the five-year average declined from 11% to 3%.
Despite lower Henry Hub spot prices since late August, we expect natural gas prices to rise this winter because of seasonal demand for natural gas for space heating, which typically peaks in January and February. We expect prices to also increase as a result of higher LNG exports as the Northern Hemisphere enters winter and the Freeport LNG terminal, which paused operations in June following a fire, resumes partial operations before the end of the year.
U.S. dry natural gas production has been generally increasing throughout 2022 and has averaged more than 98 billion cubic feet per day (Bcf/d) every month since June. We expect dry natural gas production to continue to grow, averaging 99.4 Bcf/d this winter and 99.7 Bcf/d in 2023. We forecast natural gas prices at the Henry Hub will begin to decline in the spring of 2023 as production growth continues and winter demand for heating subsides. For 2023, we forecast the annual Henry Hub price to average $5.46/MMBtu for the year.
Market Highlights:
(For the week ending Wednesday, November 16, 2022)Prices
- Henry Hub spot price: The Henry Hub spot price rose $2.29 from $3.45 per million British thermal units (MMBtu) last Wednesday to $5.74/MMBtu yesterday.
- Henry Hub futures prices: The price of the December 2022 NYMEX contract increased 33.5 cents, from $5.865/MMBtu last Wednesday to $6.200/MMBtu yesterday. The price of the 12-month strip averaging December 2022 through November 2023 futures contracts climbed 20.3 cents to $5.349/MMBtu.
- Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, November 9, to Wednesday, November 16). Week-over-week price changes at major hubs ranged from a decrease of $0.07 at SoCal Citygate in Southern California to an increase of $5.26 at the Algonquin Citygate in the Northeast.
- Prices rose in the Northeast as demand for home heating increased. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $5.26 from $2.32/MMBtu last Wednesday to $7.58/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased $5.14 from $2.23/MMBtu last Wednesday to $7.37/MMBtu yesterday. Temperatures in the Boston Area averaged 51°F this report week, 7°F lower than last report week, resulting in 42 more heating degree days (HDD). Similarly, temperatures in the New York-Central Park Area averaged 52°F this report week, 9°F lower than the last report week, resulting in 53 more HDDs. Residential and commercial consumption of natural gas in the Northeast increased by 76%, or 4.1 billion cubic feet per day (Bcf/d), compared with last week, according to data from PointLogic.
- Heating demand also rose in the Midwest this week, driving price increases. At the Chicago Citygate, the price increased $2.05 from $3.65/MMBtu last Wednesday to $5.70/MMBtu yesterday. Temperatures in the Chicago Area averaged 41°F this week, 15°F lower than last report week, resulting in 109 more HDDs. Residential and commercial consumption of natural gas in the Midwest increased 119% (4.7 Bcf/d) compared with last week, according to data from PointLogic.
- The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose $2.90 this report week, from $2.16/MMBtu last Wednesday to $5.06/MMBtu yesterday. Like other parts of the country, temperatures dropped in Texas this week, resulting in increased demand for natural gas in the residential and commercial sectors for space heating. Temperatures in the Midland-Odessa Area in West Texas averaged 45°F this week, resulting in 140 HDDs, 68 more HDDs than is normal for this time of year. Consumption of natural gas in the residential and commercial sectors in West Texas increased 0.3 Bcf/d this week, or 130%, according to data from PointLogic. Natural gas production in West Texas also decreased by 1% (0.1 Bcf/d). The increase in price at the Waha Hub resulted in the narrowing of the difference between it and the price at the Henry Hub. The Waha Hub traded 68 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded $1.29 below the Henry Hub price.
- International futures prices: International natural gas futures price movements were mixed this report week. According to Bloomberg Finance, L.P., weekly average futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased 85 cents to a weekly average of $27.06/MMBtu, and natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, increased 15 cents to a weekly average of $34.10/MMBtu.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 2 cents/MMBtu, averaging $8.95/MMBtu for the week ending November 16. Ethane prices rose 1%, while natural gas prices at the Houston Ship Channel rose 108%, narrowing the ethane premium to natural gas by 63%. Ethylene spot prices were practically unchanged. Propane prices fell 1%, while the weekly average price of crude oil fell 4%, resulting in a 9% decrease in the propane discount relative to crude oil. Normal butane prices remained relatively unchanged, and isobutane prices rose 4%. Natural gasoline prices followed crude oil prices, falling by 3%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from PointLogic, the average total supply of natural gas rose by 3.0% (3.1 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.9% (0.9 Bcf/d) to a weekly average of 101 Bcf/d, and average net imports from Canada increased by 57.2% (2.2 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas rose by 25.2% (18.2 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation climbed by 7.1% (2.1 Bcf/d) week over week. Industrial sector consumption increased by 7.1% (1.6 Bcf/d) week over week, and residential and commercial sector consumption increased by 76.6% (14.4 Bcf/d) as below-normal temperatures were experienced across most of the country. Natural gas exports to Mexico decreased 1.2% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.0 Bcf/d, or 0.5 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Overall natural gas deliveries to U.S. LNG export terminals increased by 0.5 Bcf/d week over week to average 12.0 Bcf/d this report week, according to data from PointLogic. Natural gas deliveries to LNG export terminals in South Louisiana increased by 0.5 Bcf/d to 8.4 Bcf/d, while natural gas deliveries to other LNG terminals averaged a combined 3.6 Bcf/d.
- Vessels departing U.S. ports: Twenty-two LNG vessels (eight from Sabine Pass, five from Cameron, four from Corpus Christi, two each from Cove Point and Calcasieu Pass, and one from Elba Island) with a combined LNG-carrying capacity of 82 Bcf departed the United States between November 10 and November 16, according to shipping data provided by Bloomberg Finance, L.P.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, November 8, the natural gas rig count stayed flat at 155 rigs, as gains of 1 rig each in the Eagle Ford, Haynesville, and Utica were offset by a loss of 2 rigs in the Marcellus and 1 rig in an unspecified region. The number of oil-directed rigs increased by 9 rigs from a week ago to 622 rigs. The Cana Woodford lost one rig, the Haynesville added one rig, the Permian added four rigs, and five rigs were added in an unspecified region. The total rig count, which includes 2 miscellaneous rigs, now stands at 779 rigs, which is 223 more rigs than the same week last year.
Storage
- The net injections into storage totaled 64 Bcf for the week ending November 11, compared with the five-year (2017–2021) average net withdrawals of 5 Bcf and last year's net injections of 23 Bcf during the same week. Working natural gas stocks totaled 3,644 Bcf, which is 7 Bcf (less than 1%) lower than the five-year average and 4 Bcf (less than 1%) more 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 50 Bcf to 72 Bcf, with a median estimate of 63 Bcf.
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Data source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

Spot Prices ($/MMBtu) | Thu, 10-Nov |
Fri, 11-Nov |
Mon, 14-Nov |
Tue, 15-Nov |
Wed, 16-Nov |
---|---|---|---|---|---|
Henry Hub | 4.63 | Holiday | 6.20 | 5.90 | 5.74 |
New York | 3.68 | Holiday | 6.43 | 6.44 | 7.37 |
Chicago | 5.10 | Holiday | 6.28 | 5.95 | 5.70 |
Cal. Comp. Avg.* | 8.07 | Holiday | 8.53 | 8.67 | 7.94 |
Futures ($/MMBtu) | |||||
December Contract | 6.239 | 5.879 | 5.933 | 6.034 | 6.200 |
January Contract | 6.613 | 6.263 | 6.299 | 6.395 | 6.607 |
Data source: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. |

U.S. natural gas supply - Gas Week: (11/10/22 - 11/16/22) | |||
---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
Marketed production | 113.3 |
112.5 |
106.8 |
Dry production | 100.8 |
99.9 |
95.7 |
Net Canada imports | 6.1 |
3.9 |
4.8 |
LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
Total supply | 107.1 |
103.9 |
100.6 |
Data source: PointLogic |
U.S. natural gas consumption - Gas Week: (11/10/22 - 11/16/22) | |||
---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
U.S. consumption | 90.4 |
72.2 |
76.1 |
Power | 32.5 |
30.3 |
28.6 |
Industrial | 24.7 |
23.0 |
23.7 |
Residential/commercial | 33.2 |
18.8 |
23.8 |
Mexico exports | 5.8 |
5.9 |
5.6 |
Pipeline fuel use/losses | 7.4 |
6.8 |
6.7 |
LNG pipeline receipts | 12.0 |
11.5 |
11.2 |
Total demand | 115.6 |
96.4 |
99.7 |
Data source: PointLogic |


Rigs | |||
---|---|---|---|
Tue, November 08, 2022 |
Change from |
||
last week |
last year |
||
Oil rigs | 622 |
1.5% |
37.0% |
Natural gas rigs | 155 |
0.0% |
52.0% |
Note: Excludes any miscellaneous rigs |
Rig numbers by type | |||
---|---|---|---|
Tue, November 08, 2022 |
Change from |
||
last week |
last year |
||
Vertical | 22 |
0.0% |
0.0% |
Horizontal | 711 |
0.9% |
42.5% |
Directional | 46 |
7.0% |
31.4% |
Data source: Baker Hughes Company |
Working gas in underground storage | ||||
---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
Region | 2022-11-11 |
2022-11-04 |
change |
|
East | 882 |
865 |
17 |
|
Midwest | 1,084 |
1,068 |
16 |
|
Mountain | 208 |
208 |
0 |
|
Pacific | 241 |
247 |
-6 |
|
South Central | 1,228 |
1,193 |
35 |
|
Total | 3,644 |
3,580 |
64 |
|
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report |
Working gas in underground storage | |||||
---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (11/11/21) |
5-year average (2017-2021) |
||||
Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
East | 900 |
-2.0 |
902 |
-2.2 |
|
Midwest | 1,078 |
0.6 |
1,078 |
0.6 |
|
Mountain | 212 |
-1.9 |
212 |
-1.9 |
|
Pacific | 261 |
-7.7 |
290 |
-16.9 |
|
South Central | 1,189 |
3.3 |
1,169 |
5.0 |
|
Total | 3,640 |
0.1 |
3,651 |
-0.2 |
|
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report |
Temperature – heating & cooling degree days (week ending Nov 10) | ||||||||
---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
New England | 76 |
-68 |
-72 |
1 |
1 |
1 |
||
Middle Atlantic | 68 |
-69 |
-65 |
1 |
1 |
1 |
||
E N Central | 79 |
-74 |
-56 |
0 |
0 |
0 |
||
W N Central | 127 |
-40 |
9 |
0 |
0 |
0 |
||
South Atlantic | 32 |
-55 |
-68 |
29 |
14 |
21 |
||
E S Central | 24 |
-65 |
-79 |
9 |
7 |
9 |
||
W S Central | 16 |
-38 |
-42 |
32 |
22 |
25 |
||
Mountain | 167 |
17 |
62 |
0 |
-2 |
-6 |
||
Pacific | 113 |
42 |
49 |
0 |
-1 |
0 |
||
United States | 80 |
-37 |
-26 |
10 |
5 |
7 |
||
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days |
Average temperature (°F)
7-day mean ending Nov 10, 2022

Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Nov 10, 2022

Data source: National Oceanic and Atmospheric Administration