In the News:
Industrial sector natural gas consumption returns to pre-pandemic levels
Data from EIA’s Natural Gas Monthly show that industrial natural gas consumption (not including lease and plant fuel) in September and October 2020 exceeded consumption in those months in 2019. October 2020 consumption of 22.5 billion cubic feet per day (Bcf/d) was the highest of any October in EIA’s data going back to 2001. For the first eight months of 2020, industrial consumption of natural gas remained lower than 2019 levels, and May’s consumption of 20.2 Bcf/d was the lowest level of any month since 2017.
In the first quarter of 2020, industrial natural gas consumption was lower than first-quarter 2019 by about 0.6 Bcf/d. Some of this comparative decline in industrial natural gas consumption was the result of warmer-than-normal weather. The United States had 15% (334) fewer heating degree days (HDDs) in the first quarter of 2020 than in the first quarter of 2019.
However, March marked the beginning of efforts to mitigate the spread of COVID-19 in the United States. As the pandemic progressed, a slowing economy contributed to an overall decrease in industrial output in the second quarter of 2020. Despite a colder April in 2020, which had 71 more HDDs than in April 2019, industrial consumption of natural gas fell relative to April 2019.
Since April 2020, increases in industrial activity have contributed to an increase in industrial natural gas consumption. The Short-Term Energy Outlook’s (STEO’s) natural gas-weighted industrial production index—which reflects the growth of manufacturing subsectors and the relative importance of those subsectors to total natural gas consumption—was 15% lower in April 2020 than in April 2019. From April to October, the index rose, increasing 12%.
Not all industries are recovering at the same rate, according to the Federal Reserve’s Industrial Production data, which are used to calculate the industrial indexes EIA uses in the STEO. The production index for the entire industrial sector (including lease and plant fuel) fell by 16% from January to April, and EIA expects it to rise higher than January 2020 levels by March 2022 (based on IHS Markit economic forecasts used in the STEO). The index for chemicals, a natural-gas-intensive industry, had less of an initial decrease (6%), and returned to January 2020 levels by the end of 2020. However, the production index for primary metals (which is less natural gas intensive) fell initially by 28%, and does not return to pre-pandemic levels (January 2020 levels) during the STEO forecast period (through 2022).
Quicker recovery in industries that consume more natural gas allowed total industrial natural gas consumption to return to pre-pandemic levels in the final months of 2020, even as total industrial output did not. EIA’s STEO forecasts November 2020 industrial natural gas consumption was less than November 2019 levels by 0.5 Bcf/d, but December 2020 was 0.2 Bcf/d higher than in December 2019.
Overview:
(For the week ending Wednesday, January 27, 2021)
- Natural gas spot prices rose at most locations this report week (Wednesday, January 20 to Wednesday, January 27). The Henry Hub spot price rose from $2.42 per million British thermal units (MMBtu) last Wednesday to $2.71/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the February 2021 contract expired yesterday at $2.702/MMBtu, up 16¢/MMBtu from last Wednesday. The March 2021 contract price increased to $2.720/MMBtu, up 19¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging March 2021 through February 2022 futures contracts climbed 14¢/MMBtu to $2.915/MMBtu.
- The net withdrawals from working gas totaled 128 billion cubic feet (Bcf) for the week ending January 22. Working natural gas stocks totaled 2,881 Bcf, which is 3% more than the year-ago level and 9% more than the five-year (2016–2021) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 25¢/MMBtu, averaging $7.10/MMBtu for the week ending January 27. The prices of propane, butane, and isobutane fell by 6%, 5%, and 4%, respectively. The price of natural gasoline rose by 1%. The price of ethane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, January 19, the natural gas rig count increased by 3 to 88. The number of oil-directed rigs rose by 2 to 289. The total rig count increased by 5, and it now stands at 378.
Prices/Supply/Demand:
Prices end week on highs at most key trading hubs. This report week (Wednesday, January 20 to Wednesday, January 27), the Henry Hub spot price rose 29¢ from a low of $2.42/MMBtu last Wednesday to a high of $2.71/MMBtu yesterday. Temperatures were generally cooler than normal across most of the Lower 48 states and warmer than normal on the eastern seaboard, especially in the Southeast. At the Chicago Citygate, the price increased 26¢ from a low of $2.36/MMBtu last Wednesday to a high of $2.62/MMBtu yesterday.
California prices increase. The price at SoCal Citygate in Southern California increased 53¢ from a low of $2.93/MMBtu last Wednesday to $3.46/MMBtu yesterday amid a cold front. The price at PG&E Citygate in Northern California rose 20¢, up from a low of $3.36/MMBtu last Wednesday to a high of $3.56/MMBtu yesterday.
Northeast prices rise. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $6.86 from a low of $3.04/MMBtu last Wednesday to a high of $9.90/MMBtu yesterday amid forecasts of snow for today and in the next report week. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased $2.77 from a low of $2.40/MMBtu last Wednesday to a high of $5.17/MMBtu yesterday because of cold temperatures.
The Tennessee Zone 4 Marcellus spot price increased 30¢ from $2.13/MMBtu last Wednesday to $2.43/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania rose 26¢ from $2.18/MMBtu last Wednesday to $2.44/MMBtu yesterday.
Permian Basin prices end week on a high. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $2.32/MMBtu last Wednesday, 10¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged a high of $2.60/MMBtu, 11¢/MMBtu lower than the Henry Hub price.
WhiteWater Midstream and MPLX LP’s Agua Blanca, a 1.8 billion cubic feet per day (Bcf/d) expansion project, has entered commercial service this week, according to Natural Gas Intelligence. The project connects 20 natural gas processing sites and transports natural gas from the Delaware Basin in the Permian to the Waha Hub. On January 24, Grupo Carso’s Samalayuca-Sasabe pipeline in Northwest Mexico began to receive commercial flows of natural gas for the first time. The 0.47 Bcf/d pipeline increases natural gas export capacity from West Texas into Mexico via IEnova’s San Isidro-Samalayuca (SIS) pipeline.
Supply rises with higher exports from Canada. According to data from IHS Markit, the average total supply of natural gas rose by 0.8% compared with the previous report week. Dry natural gas production grew by 0.2% compared with the previous report week. Average net imports from Canada increased by 8.4% from last week.
Demand rises, driven by space heating and power generation. Total U.S. consumption of natural gas rose by 6.2% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 2.0% week over week. In the residential and commercial sectors, consumption increased by 12.5%. Industrial sector consumption increased by 0.9% week over week. Natural gas exports to Mexico increased 7.2%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 9.9 Bcf/d, or 0.9 Bcf/d lower than last week.
U.S. LNG exports decrease week over week. Eighteen liquefied natural gas (LNG) vessels (five from Sabine Pass, four each from Cameron, Corpus Christi, and Freeport, and one from Cove Point) with a combined LNG-carrying capacity of 65 Bcf departed the United States between January 21 and January 27, 2021, according to shipping data provided by Bloomberg Finance, L.P.
During the report week, U.S. LNG traffic flow was affected by the weather conditions (fog) at Sabine Pass LNG, Corpus Christi LNG, and Cameron LNG. Piloting services in the waterways around Corpus Christi LNG were suspended for part of the day on January 21, 2021. Pilot services were suspended for Sabine Pass LNG traffic on January 21, 23, and 25 because of fog conditions. Weather-related closures were also reported for several days at Lake Charles—the location of Cameron LNG.
On January 26, 2021, a new record for U.S. LNG daily loadings was set. EIA estimates that 25.4 Bcf were loaded on seven LNG tankers that departed U.S. LNG terminals on that day.
Storage:
The net withdrawals from storage totaled 128 Bcf for the week ending January 22, compared with the five-year (2016–2021) average net withdrawals of 174 Bcf and last year's net withdrawals of 170 Bcf during the same week. Working natural gas stocks totaled 2,881 Bcf, which is 244 Bcf more than the five-year average and 78 Bcf 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 withdrawals of 121 Bcf to 145 Bcf, with a median estimate of 136 Bcf.
The average rate of withdrawals from storage is 4% lower than 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 12.2 Bcf/d for the remainder of the withdrawal season, the total inventory would be 2,050 Bcf on March 31, which is 244 Bcf higher than the five-year average of 1,806 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:
| Spot Prices ($/MMBtu) | Thu, 21-Jan |
Fri, 22-Jan |
Mon, 25-Jan |
Tue, 26-Jan |
Wed, 27-Jan |
|---|---|---|---|---|---|
| Henry Hub |
2.43 |
2.42 |
2.54 |
2.63 |
2.71 |
| New York |
2.50 |
2.81 |
2.50 |
2.82 |
5.17 |
| Chicago |
2.43 |
2.38 |
2.49 |
2.58 |
2.62 |
| Cal. Comp. Avg.* |
2.86 |
2.86 |
3.06 |
3.20 |
3.07 |
| Futures ($/MMBtu) | |||||
| February contract | 2.491 |
2.446 |
2.602 |
2.656 |
2.702 |
| March contract |
2.497 |
2.456 |
2.598 |
2.636 |
2.720 |
| *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: (1/21/21 - 1/27/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 102.3 |
102.1 |
105.2 |
| Dry production | 90.5 |
90.3 |
93.4 |
| Net Canada imports | 6.1 |
5.6 |
5.2 |
| LNG pipeline deliveries | 0.3 |
0.2 |
0.3 |
| Total supply | 96.9 |
96.1 |
99.0 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (1/21/21 - 1/27/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 94.7 |
89.2 |
97.5 |
| Power | 27.0 |
26.5 |
30.4 |
| Industrial | 24.9 |
24.7 |
25.6 |
| Residential/commercial | 42.8 |
38.1 |
41.5 |
| Mexico exports | 5.9 |
5.5 |
5.3 |
| Pipeline fuel use/losses | 7.0 |
7.2 |
8.1 |
| LNG pipeline receipts | 9.9 |
10.9 |
9.0 |
| Total demand | 117.6 |
112.7 |
119.8 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
January 22, 2021
|
Change from |
||
last week |
last year |
||
| Oil rigs | 289 |
0.7% |
-57.2% |
| Natural gas rigs | 88 |
3.5% |
-23.5% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
January 22, 2021
|
Change from |
||
last week |
last year |
||
| Vertical | 18 |
-5.3% |
-51.4% |
| Horizontal | 338 |
1.8% |
-52.4% |
| Directional | 22 |
0.0% |
-53.2% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2021-01-22 |
2021-01-15 |
change |
|
| East | 641 |
679 |
-38 |
|
| Midwest | 780 |
828 |
-48 |
|
| Mountain | 170 |
176 |
-6 |
|
| Pacific | 275 |
275 |
0 |
|
| South Central | 1,014 |
1,051 |
-37 |
|
| Total | 2,881 |
3,009 |
-128 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (1/22/20) |
5-year average (2016-2020) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 655 |
-2.1 |
605 |
6.0 |
|
| Midwest | 776 |
0.5 |
718 |
8.6 |
|
| Mountain | 145 |
17.2 |
148 |
14.9 |
|
| Pacific | 213 |
29.1 |
225 |
22.2 |
|
| South Central | 1,015 |
-0.1 |
942 |
7.6 |
|
| Total | 2,803 |
2.8 |
2,637 |
9.3 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jan 21) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 212 |
-63 |
-60 |
0 |
0 |
0 |
||
| Middle Atlantic | 209 |
-54 |
-38 |
0 |
0 |
0 |
||
| E N Central | 242 |
-55 |
-41 |
0 |
0 |
0 |
||
| W N Central | 248 |
-68 |
-88 |
0 |
0 |
0 |
||
| South Atlantic | 167 |
-16 |
15 |
1 |
-7 |
-9 |
||
| E S Central | 166 |
-22 |
12 |
0 |
-2 |
0 |
||
| W S Central | 113 |
-27 |
20 |
0 |
-4 |
-8 |
||
| Mountain | 195 |
-37 |
-17 |
0 |
0 |
0 |
||
| Pacific | 72 |
-48 |
-56 |
0 |
-1 |
0 |
||
| United States | 180 |
-46 |
-32 |
0 |
-2 |
-3 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Jan 21, 2021
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Jan 21, 2021
Source: National Oceanic and Atmospheric Administration
