In the News:
Near-record cold temperatures drive near-record withdrawals from working natural gas stocks in the Lower 48 states
Working natural gas storage operators reported the second-largest weekly total net withdrawals ever reported for the Lower 48 states following a week characterized by widespread extreme cold throughout most of the country, which increased heating demand for natural gas. Net withdrawals from underground natural gas storage facilities totaled 338 billion cubic feet (Bcf) for the week ending February 19, 2021, exceeding the historical five-year average net withdrawals for the week by 218 Bcf (182%). Last week’s withdrawals were 21 Bcf lower than the all-time weekly record withdrawal of 359 Bcf, which was reported for the week ending January 5, 2018. As a result, working gas stocks fell to less than the five-year average by 161 Bcf.
Natural gas consumption in each of the main demand sectors increased during the report week, according to IHS Markit. Residential and commercial consumption averaged 62 billion cubic feet per day (Bcf/d) during the report week—the second-highest level in history after the record level of 64 Bcf/day reported for the week ending January 5, 2018. Electric power consumption of natural gas surpassed 33 Bcf/d, setting a new record winter high. In addition, industrial sector demand set a new record high of 28 Bcf/d.
Declines in production during the report week as a result of freeze-offs and shut-ins at natural gas wells in the Permian Basin also contributed to the increased withdrawals. Dry gas production in the Lower 48 states fell 12 Bcf/day to 77 Bcf/day for the week ending February 19, according to IHS Markit. Exports—both liquefied natural gas (LNG) and pipeline exports— declined 6.7 Bcf/day during the week, which lessened some of the need to withdraw natural gas from storage. Pipeline imports from Canada increased by 1.5 Bcf/day over the previous week to their highest levels since January 2010, which offset some of the declines in U.S. natural gas production.
Net withdrawals from natural gas storage facilities tend to be highly correlated with cold temperatures, which increase heating demand and, by extension, demand for natural gas. The first graph depicts this historical correlation between the weekly net change in working gas stocks and heating degree days (HDD)—a temperature-based measure of heating demand— during the heating season months (November 1–March 31) from January 2010 through last week.
Net changes in working gas stocks during the 2020–21 heating season (shown as red in the first graph) followed the general historical pattern, with higher HDDs generally leading to larger net withdrawals from working gas. During the first three months of the 2020–21 heating season weekly HDDs did not exceed 188 HDDs and the weekly net withdrawals also remained relatively small, with the largest weekly net withdrawal during this period totaling 187 Bcf. However, a period of sustained colder temperatures following the week ending January 28 resulted in a significant increase in HDDs and increased withdrawal activity. This increase peaked with the most recent report week, when significantly colder-than-normal temperatures resulted in 254 HDDs for the Lower 48 states—the third largest weekly total in history. Similarly, the largest weekly net withdrawals (359 Bcf) reported in the Lower 48 states coincided with the record-level 273 HDDs reported for the week ending January 5, 2018 (shown as green in the first graph).
The colder winter temperatures since late January prompted some of the largest natural gas storage withdrawal activity since the 2017–18 heating season. Total net withdrawals from underground natural gas storage facilities totaled 938 Bcf in the past four weeks (January 22—February 19). The cumulative withdrawals made up the third-largest four-week total reported since 2010, exceeded only by the record-setting 2013–14 and the 2017–18 heating seasons. In fact, two of the 15 largest weekly net withdrawals from storage occurred in the past two weeks.
The surplus to the five-year average natural gas inventory level has fallen in recent weeks because of higher natural gas storage withdrawals. The surplus to the five-year average last peaked at 244 Bcf on January 22. However, since then, net withdrawals have exceeded the five-year average. Working gas stocks are now 161 Bcf lower than the five-year average—the first deficit since December 2019.
Overview:
(For the week ending Wednesday, February 24, 2021)
- Natural gas spot prices fell at most locations this report week (Wednesday, February 17 to Wednesday, February 24) as temperatures across most of the Lower 48 states returned to normal or above-normal and heating and electricity demand declined from record-setting levels. The Henry Hub spot price fell from $23.61 per million British thermal units (MMBtu) last Wednesday to $2.75/MMBtu yesterday.
- At the New York Mercantile Exchange (NYMEX), the March 2021 contract expired yesterday at $2.854/MMBtu, down 37¢/MMBtu from last Wednesday. The April 2021 contract price decreased to $2.795/MMBtu, down 24¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging April 2021 through March 2022 futures contracts declined 18¢/MMBtu to $2.964/MMBtu.
- The net withdrawals from working gas totaled 338 billion cubic feet (Bcf) for the week ending February 19. Working natural gas stocks totaled 1,943 Bcf, which is 13% lower than the year-ago level and 8% lower than the five-year (2016–2021) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 26¢/MMBtu, averaging $7.92/MMBtu for the week ending February 24. The price of ethane fell by 14%, reflecting declines in natural gas prices to which ethane prices are most closely correlated. Average weekly propane spot prices rose 10%, reflecting the highest weekly levels since October 2018. The prices of natural gasoline, normal butane, and isobutane rose by 7%, 5%, and 7%, respectively.
- According to Baker Hughes, for the week ending Tuesday, February 16, the natural gas rig count increased by 1 to 91. The number of oil-directed rigs fell by 1 to 305. The total rig count stayed at 397.
Prices/Supply/Demand:
Prices across the country fall sharply from all-time highs. This report week (Wednesday, February 17 to Wednesday, February 24), the Henry Hub spot price fell $20.86 from $23.61/MMBtu last Wednesday to $2.75/MMBtu yesterday. At the Chicago Citygate, the price decreased $16.14 from $18.82/MMBtu last Wednesday to $2.68/MMBtu yesterday.
Northeast prices decline but from less elevated levels than in other regions. At the Algonquin Citygate, which serves Boston-area consumers, the price decreased $7.12 from $10.60/MMBtu last Wednesday to $3.48/MMBtu yesterday after reaching a weekly low on Tuesday at $3.18/MMBtu. At the Transcontinental Pipeline (Transco) Zone 6 trading point for New York City, the price decreased $10.85 from $13.50/MMBtu last Wednesday to $2.65/MMBtu yesterday. Algonquin Citygate and Transco Zone 6 both recorded weekly lows on Tuesday at $3.18/MMBtu and $2.59/MMBtu respectively.
Appalachia’s production basin prices declined week over week, but they remain higher than average January prices. The Tennessee Zone 4 Marcellus spot price decreased $2.82 from $5.13/MMBtu last Wednesday to $2.31/MMBtu yesterday after declining to a weekly low of $2.10/MMBtu on Tuesday. The price at Dominion South in southwest Pennsylvania fell $3.53 from $5.92/MMBtu last Wednesday to $2.39/MMBtu yesterday after recording a weekly low of $2.27/MMBtu on Tuesday. Prices at Tennessee Zone 4 and Dominion South were $0.04/MMBtu and $0.07/MMBtu higher yesterday, respectively, than they were on average in January.
Permian Basin prices decline as production increases and demand subsides. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, hit a weekly low of $2.56/MMBtu on Tuesday before settling at $2.65/MMBtu yesterday, which was $61.57/MMBtu lower than last Wednesday’s price of $64.22/MMBtu, and $203.50/MMBtu lower than the all-time record of $206.19/MMBtu set on Tuesday, February 16. Waha Hub prices were $40.61/MMBtu higher than the Henry Hub price last Wednesday. Yesterday, the price at the Waha Hub returned to a discount to Henry Hub at 10¢/MMBtu lower than Henry Hub.
California prices return to historical trend. The price at PG&E Citygate in Northern California fell $3.21, down from $6.90/MMBtu last Wednesday to $3.69/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased $23.65 from $26.93/MMBtu last Wednesday to $3.28/MMBtu yesterday. The SoCal Citygate price is now back to a discount relative to PG&E, reflecting a return to lower prices at the Waha hub in the Permian Basin (where much of the natural gas for Southern California is sourced) relative to the Malin Hub on the California/Oregon border (where much of the natural gas delivered to Northern California is sourced). Malin prices peaked at $11.05/MMBtu last Tuesday, February 16, $195.14/MMBtu lower than Waha that day, and closed out last report week on Wednesday at $88.99/MMBtu lower than Waha. This Wednesday, Malin prices fell to $2.75/MMBtu, but they are now at a $0.10/MMBtu premium to Waha.
Supply rises, but remains lower than the week before last. According to data from IHS Markit, the average total supply of natural gas rose by 2.9% compared with the previous report week. After last week’s production losses due to freeze-offs, dry natural gas production increased by 4.1% compared with the previous report week. Dry gas production remains lower than normal at an estimated 9.2% lower than the week ending February 10 and 13.6% lower than the same week last year. Average net imports from Canada decreased by 9.1% from last week, but they remain elevated at 12.4% higher than the prior week and 25.3% higher than the same week last year.
Demand declines in response to lower heating and power demand. Total U.S. consumption of natural gas fell by 20.8% compared with the previous report week, according to data from IHS Markit. Consumption in the residential and commercial sectors declined by an estimated 28.1%, or 17.65 Bcf/d, the highest weekly decline on record. Natural gas consumed for power generation declined by 16.1% week over week. Industrial sector consumption decreased by 9.9% week over week. Natural gas exports to Mexico increased 0.7%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 7.4 Bcf/d, or 1.2 Bcf/d higher than last week.
U.S. LNG exports increase week over week. Fourteen LNG vessels (seven from Sabine Pass; two each from Cove Point and Cameron; and one each from Corpus Christi, Elba Island, and Freeport) with a combined LNG-carrying capacity of 50 Bcf departed the United States between February 18 and February 24, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net withdrawals from storage totaled 338 Bcf for the week ending February 19, compared with the five-year (2016–2021) average net withdrawals of 120 Bcf and last year's net withdrawals of 145 Bcf during the same week. Working natural gas stocks totaled 1,943 Bcf, which is 161 Bcf lower than the five-year average and 298 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 287 Bcf to 371 Bcf, with a median estimate of 336 Bcf.
The average rate of withdrawals from storage is 22% higher 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 7.5 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,645 Bcf on March 31, which is 161 Bcf lower 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, 18-Feb |
Fri, 19-Feb |
Mon, 22-Feb |
Tue, 23-Feb |
Wed, 24-Feb |
|---|---|---|---|---|---|
| Henry Hub |
7.50 |
4.99 |
2.84 |
2.79 |
2.75 |
| New York |
5.87 |
7.06 |
2.69 |
2.59 |
2.65 |
| Chicago |
6.22 |
3.94 |
2.72 |
2.72 |
2.68 |
| Cal. Comp. Avg.* |
5.03 |
3.80 |
3.27 |
3.19 |
3.16 |
| Futures ($/MMBtu) | |||||
| March contract | 3.082 |
3.069 |
2.953 |
2.879 |
2.854 |
| April contract |
2.970 |
2.991 |
2.936 |
2.857 |
2.795 |
| *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: (2/18/21 - 2/24/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 92.9 |
88.7 |
106.4 |
| Dry production | 82.7 |
79.5 |
94.0 |
| Net Canada imports | 6.8 |
7.4 |
5.4 |
| LNG pipeline deliveries | 0.4 |
0.5 |
0.2 |
| Total supply | 89.9 |
87.4 |
99.6 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (2/18/21 - 2/24/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 97.7 |
123.3 |
95.8 |
| Power | 27.1 |
32.3 |
30.3 |
| Industrial | 25.4 |
28.2 |
25.2 |
| Residential/commercial | 45.2 |
62.8 |
40.3 |
| Mexico exports | 4.9 |
4.9 |
5.2 |
| Pipeline fuel use/losses | 6.8 |
7.5 |
7.4 |
| LNG pipeline receipts | 7.4 |
6.2 |
8.6 |
| Total demand | 116.8 |
141.9 |
117.0 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, February 16, 2021 |
Change from |
||
last week |
last year |
||
| Oil rigs | 305 |
-0.3% |
-55.1% |
| Natural gas rigs | 91 |
1.1% |
-17.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, February 16, 2021 |
Change from |
||
last week |
last year |
||
| Vertical | 24 |
4.3% |
-25.0% |
| Horizontal | 357 |
0.3% |
-50.0% |
| Directional | 16 |
-11.1% |
-64.4% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2021-02-19 |
2021-02-12 |
change |
|
| East | 424 |
485 |
-61 |
|
| Midwest | 508 |
589 |
-81 |
|
| Mountain | 123 |
137 |
-14 |
|
| Pacific | 218 |
244 |
-26 |
|
| South Central | 670 |
826 |
-156 |
|
| Total | 1,943 |
2,281 |
-338 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (2/19/20) |
5-year average (2016-2020) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 496 |
-14.5 |
440 |
-3.6 |
|
| Midwest | 605 |
-16.0 |
537 |
-5.4 |
|
| Mountain | 111 |
10.8 |
119 |
3.4 |
|
| Pacific | 197 |
10.7 |
197 |
10.7 |
|
| South Central | 832 |
-19.5 |
811 |
-17.4 |
|
| Total | 2,241 |
-13.3 |
2,104 |
-7.7 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Feb 18) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 269 |
10 |
25 |
0 |
0 |
0 |
||
| Middle Atlantic | 272 |
26 |
42 |
0 |
0 |
0 |
||
| E N Central | 372 |
106 |
97 |
0 |
0 |
0 |
||
| W N Central | 465 |
195 |
166 |
0 |
0 |
0 |
||
| South Atlantic | 186 |
26 |
56 |
16 |
9 |
-2 |
||
| E S Central | 257 |
99 |
119 |
0 |
-1 |
0 |
||
| W S Central | 290 |
183 |
191 |
0 |
-4 |
-7 |
||
| Mountain | 272 |
72 |
63 |
0 |
-1 |
0 |
||
| Pacific | 125 |
22 |
25 |
0 |
0 |
0 |
||
| United States | 279 |
81 |
83 |
3 |
1 |
-1 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Feb 18, 2021
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Feb 18, 2021
Source: National Oceanic and Atmospheric Administration
