Today in Energy
Recent Today in Energy analysis of natural gas markets is available on the EIA website.
Market Highlights:
(For the week ending Wednesday, January 8, 2025)Prices
- Henry Hub spot price: The Henry Hub spot price rose 37 cents from $3.39 per million British thermal units (MMBtu) last Wednesday to $3.76/MMBtu this Wednesday.
- Henry Hub futures price: The January 2025 contract expired on Friday, December 27, at $3.514/MMBtu. The price of the February 2025 NYMEX contract decreased 1 cent, from $3.660/MMBtu last Thursday to $3.651/MMBtu this Wednesday. The price of the 12-month strip averaging February 2025 through January 2026 futures contracts increased 3 cents to $3.678/MMBtu.
- Select regional spot prices: Natural gas spot prices rose at all major pricing locations this report week (Wednesday, January 1, to Wednesday, January 8). Price increases ranged from 29 cents at Eastern Gas South to $11.69 at Algonquin Citygate.
- Prices increased in the Northeast this report week as cold weather moved into the region. At the Algonquin Citygate, which serves Boston-area consumers, the price rose $11.69 from $4.86/MMBtu last Wednesday to $16.55/MMBtu this Wednesday. At the Transco Zone 6 NY trading point for New York City, the price increased $8.13 from $3.37/MMBtu last Wednesday to $11.50/MMBtu this Wednesday. Natural gas consumption in the Northeast increased by 43% (10.2 billion cubic feet per day [Bcf/d]) this report week, led by a 71% (8.1 Bcf/d) increase in consumption in the residential and commercial sector, according to S&P Global Commodity Insights. Temperatures in the New York-Central Park Area averaged 30°F this week, 4°F below normal and 15°F below the previous week, resulting in 241 heating degree days (HDDs), 28 HDDs more than normal and 101 more than last week. The price at Eastern Gas South near Appalachian Basin production activities rose 29 cents from $3.03/MMBtu last Wednesday to $3.32/MMBtu this Wednesday. Natural gas net imports from Canada into the Northeast more than tripled to 1.2 Bcf/d this report week, according to data from S&P Global Commodity Insights, to supplement Appalachia production that was down 3% (0.9 Bcf/d) possibly because of the colder temperatures.
- On the West Coast, prices increased this report week. At Northwest Sumas on the Canada-Washington border, the main pricing point for natural gas in the Pacific Northwest, the price rose 58 cents from $2.70/MMBtu last Wednesday to $3.28/MMBtu this Wednesday. At PG&E Citygate in Northern California, the price increased 50 cents from $3.05/MMBtu last Wednesday to $3.55/MMBtu this Wednesday. The price at SoCal Citygate in Southern California increased 43 cents from $3.59 last Wednesday to $4.02/MMBtu this Wednesday. Natural gas consumption in the Western region increased by 4% (0.5 Bcf/d) this report week, according to data from S&P Global Commodity Insights. On January 8, more than 1.5 million people were reported without power in California as wildfires spread across the Los Angeles area. The number of customers without power due to a Public Safety Power Shutoff will change daily, according to Southern California Edison, while the fires remain active. San Diego Gas and Electric is shutting off power intermittently to customers as well because of the wildfires.
- Prices in Texas increased this report week as consumption of natural gas increased. At the Houston Ship Channel, the price rose 92 cents from $2.59/MMBtu last Wednesday to $3.51/MMBtu this Wednesday. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, increased $2.97 from $0.09/MMBtu last Wednesday to $3.06/MMBtu this Wednesday. The Waha Hub traded 70 cents below the Henry Hub price this Wednesday, compared with last Wednesday when it traded $3.30 below the Henry Hub price. Natural gas consumption in Texas increased 24% (2.7 Bcf/d) this report week, according to S&P Global Commodity Insights. Temperatures in the Houston Area averaged 51°F this week, 2°F below normal and 12°F below the previous week, which resulted in 93 HDDs, or 7 HDDs more than normal and 75 more than last week. In addition, net exports to Mexico from Texas were up 20% (1.0 Bcf/d) this report week.
- International futures prices: International natural gas futures prices increased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia increased 14 cents to a weekly average of $14.30/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased 6 cents to a weekly average of $14.55/MMBtu. In the same week last year (week ending January 10, 2024), the prices were $11.44/MMBtu in East Asia and $10.35/MMBtu at TTF.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 31 cents/MMBtu, averaging $8.13/MMBtu for the week ending January 8. Ethane prices rose 13% week over week, while weekly average natural gas prices at the Houston Ship Channel increased 10%, widening the ethane premium to natural gas by 22%. The ethylene spot price was relatively unchanged week over week, and the ethylene premium to ethane decreased 6%. Propane prices decreased 4%, while Brent crude oil prices decreased 2% week over week. The propane discount to crude oil was relatively unchanged for the week. Normal butane prices fell 6%, isobutane prices fell 1%, and natural gasoline prices rose 2%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 0.2% (0.3 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 2.2% (2.3 Bcf/d) to average 103.4 Bcf/d, and average net imports from Canada increased by 47.0% (2.5 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas rose by 32.0% (28.1 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumption in the residential and commercial sector increased by 60.2% (19.8 Bcf/d), as widespread cold weather affected most of the United States. Natural gas consumed for power generation rose by 20.2% (6.1 Bcf/d), and consumption in the industrial sector increased by 8.9% (2.2 Bcf/d) week over week. Natural gas net exports to Mexico increased 19.3% (1.0 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 15.2 Bcf/d, or 0.1 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals increased 0.1 Bcf/d from last week to 15.2 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana were essentially unchanged at 9.2 Bcf/d, while natural gas deliveries to terminals in South Texas increased by 3.5% (0.2 Bcf/d) to 4.8 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast averaged 1.2 Bcf/d this week.
- Vessels departing U.S. ports: Twenty-seven LNG vessels (nine from Sabine Pass, five from Corpus Christi, four each from Cameron and Freeport, three from Calcasieu Pass, and one each from Cove Point and Plaquemines) with a combined LNG-carrying capacity of 102 Bcf departed the United States between January 2 and January 8, according to shipping data provided by Bloomberg Finance, L.P.
- LNG Terminals: Plaquemines LNG became the eighth operating LNG terminal in the United States after achieving first LNG production in mid-December 2024. Plaquemines LNG shipped its first LNG cargo on December 26, 2024.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, December 31, the natural gas rig count increased by 1 rig from a week ago to 103 rigs, as 1 rig was added among unidentified producing regions. The number of oil-directed rigs decreased by 1 rig from a week ago to 482 rigs. The Cana Woodford added one rig, while two rigs were dropped among unidentified producing regions. The total rig count, which includes 4 miscellaneous rigs, now stands at 589 rigs, 32 fewer rigs than last year at this time.
Storage
- Net withdrawals from storage totaled 40 Bcf for the week ending January 3, compared with the five-year (2020–24) average net withdrawals of 93 Bcf and last year's net withdrawals of 104 Bcf during the same week. Working natural gas stocks totaled 3,373 Bcf, which is 207 Bcf (7%) more than the five-year average and 3 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 withdrawals of 28 Bcf to 68 Bcf, with a median estimate of 38 Bcf.
- The average rate of withdrawals from storage is the same as the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 15.0 Bcf/d for the remainder of the withdrawal season, the total inventory would be 2,067 Bcf on March 31, which is 207 Bcf higher than the five-year average of 1,860 Bcf for that time of year.
See also:
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Spot Prices ($/MMBtu) | Thu, 2-Jan |
Fri, 3-Jan |
Mon, 6-Jan |
Tue, 7-Jan |
Wed, 8-Jan |
---|---|---|---|---|---|
Henry Hub | 3.66 | 3.47 | 4.06 | 3.98 | 3.76 |
New York | 3.75 | 5.86 | 12.75 | 15.00 | 11.50 |
Chicago | 3.33 | 3.37 | 3.96 | 3.75 | 3.55 |
Cal. Comp. Avg,* | 3.12 | 3.13 | 3.86 | 3.36 | 3.40 |
*Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
Data source: NGI's Daily Gas Price Index |
Spot Prices ($/MMBtu) | Thu, 26-Dec |
Fri, 27-Dec |
Mon, 30-Dec |
Tue, 31-Dec |
Wed, 1-Jan |
---|---|---|---|---|---|
Henry Hub | 2.96 | 2.80 | 3.40 | 3.39 | Holiday |
New York | 3.09 | 2.34 | 2.88 | 3.37 | Holiday |
Chicago | 2.63 | 2.34 | 2.98 | 3.10 | Holiday |
Cal. Comp. Avg,* | 2.36 | 2.02 | 3.19 | 2.90 | Holiday |
*Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
Data source: NGI's Daily Gas Price Index |
Spot Prices ($/MMBtu) | Thu, 19-Dec |
Fri, 20-Dec |
Mon, 23-Dec |
Tue, 24-Dec |
Wed, 25-Dec |
---|---|---|---|---|---|
Henry Hub | 3.13 | 3.10 | 2.94 | 3.01 | Holiday |
New York | 3.36 | 10.00 | 3.11 | 3.79 | Holiday |
Chicago | 2.94 | 2.83 | 2.72 | 2.77 | Holiday |
Cal. Comp. Avg,* | 3.06 | 2.95 | 2.76 | 2.74 | Holiday |
*Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
Data source: NGI's Daily Gas Price Index |


U.S. natural gas supply - Gas Week: (1/2/25 - 1/8/25) | |||
---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
Marketed production | 117.1 |
119.7 |
117.0 |
Dry production | 103.4 |
105.7 |
104.0 |
Net Canada imports | 7.9 |
5.4 |
7.0 |
LNG pipeline deliveries | 0.1 |
0.0 |
0.1 |
Total supply | 111.4 |
111.1 |
111.2 |
Data source: S&P Global Commodity Insights |
U.S. natural gas consumption - Gas Week: (1/2/25 - 1/8/25) | |||
---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
U.S. consumption | 115.8 |
87.7 |
106.1 |
Power | 36.6 |
30.4 |
35.8 |
Industrial | 26.6 |
24.4 |
25.3 |
Residential/commercial | 52.7 |
32.9 |
44.9 |
Mexico exports | 6.2 |
5.2 |
5.8 |
Pipeline fuel use/losses | 8.3 |
7.5 |
8.2 |
LNG pipeline receipts | 15.2 |
15.1 |
14.9 |
Total demand | 145.5 |
115.5 |
135.0 |
Data source: S&P Global Commodity Insights |


Rigs | |||
---|---|---|---|
Tue, December 31, 2024 |
Change from |
||
last week
|
last year
|
||
Oil rigs |
482
|
-0.2%
|
-3.8%
|
Natural gas rigs |
103
|
1.0%
|
-12.7%
|
Note: Excludes any miscellaneous rigs |
Rig numbers by type | |||
---|---|---|---|
Tue, December 31, 2024 |
Change from |
||
last week
|
last year
|
||
Vertical |
13
|
0.0%
|
18.2%
|
Horizontal |
527
|
0.0%
|
-6.6%
|
Directional |
49
|
0.0%
|
6.5%
|
Data source: Baker Hughes Company |
Working gas in underground storage | ||||
---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
Region |
2025-01-03 |
2024-12-27 |
change |
|
East |
737 |
745 |
-8 |
|
Midwest |
881 |
914 |
-33 |
|
Mountain |
255 |
262 |
-7 |
|
Pacific |
293 |
295 |
-2 |
|
South Central |
1,207 |
1,197 |
10 |
|
Total |
3,373 |
3,413 |
-40 |
|
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report Note: Totals may not equal sum of components because of independent rounding. |
Working gas in underground storage | |||||
---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago 1/3/24 |
5-year average 2020-2024 |
||||
Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
East |
769 |
-4.2 |
745 |
-1.1 |
|
Midwest |
937 |
-6.0 |
886 |
-0.6 |
|
Mountain |
222 |
14.9 |
181 |
40.9 |
|
Pacific |
276 |
6.2 |
235 |
24.7 |
|
South Central | 1,172 |
3.0 |
1,119 |
7.9 |
|
Total | 3,376 |
-0.1 |
3,166 |
6.5 |
|
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report
Note: Totals may not equal sum of components because of independent rounding. |
Temperature – heating & cooling degree days (week ending Jan 02) | ||||||||
---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
New England | 197 |
-66 |
5 |
0 |
0 |
0 |
||
Middle Atlantic | 198 |
-52 |
7 |
0 |
0 |
0 |
||
E N Central | 188 |
-97 |
-27 |
0 |
0 |
0 |
||
W N Central | 212 |
-97 |
-30 |
0 |
0 |
0 |
||
South Atlantic | 118 |
-59 |
-26 |
8 |
1 |
6 |
||
E S Central | 105 |
-79 |
-72 |
0 |
-1 |
0 |
||
W S Central | 76 |
-61 |
-70 |
3 |
1 |
3 |
||
Mountain | 202 |
-34 |
-9 |
0 |
0 |
0 |
||
Pacific | 105 |
-21 |
-3 |
0 |
0 |
0 |
||
United States | 157 |
-63 |
-22 |
2 |
1 |
2 |
||
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days |
Average temperature (°F)
7-day mean ending Jan 02, 2025

Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Jan 02, 2025

Data source: National Oceanic and Atmospheric Administration
Monthly U.S. dry shale natural gas production by formation is available in the Short-Term Energy Outlook.