In the News:
Fluctuating weather this winter has significantly affected natural gas prices in New England and Southern California
From November 1, 2021 through February 16, 2022, movements of the spot price of natural gas at the benchmark Henry Hub in Louisiana have trended with weather shifts across the country. The Henry Hub price has fluctuated between a low of $3.30 per million British thermal units (MMBtu) on December 27, 2021, and a high of $6.44/MMBtu on February 2, 2022, following weather patterns that were warmer than normal in November and December to colder than normal for much of January and early February (based on analysis of daily price data from Natural Gas Intelligence and natural gas-weighted heating degree days (HDD) data from the National Oceanic and Atmospheric Administration (NOAA)).
Natural gas prices in the United States fluctuate during the winter months due to a variety of factors, including the levels of natural gas inventories, production, consumption, exports, pipeline congestion, availability and competition with other energy sources in electricity generation, and weather. Unusually cold winter weather events result in increased demand for space heating and may be accompanied by production disruptions (such as well freeze-offs) or natural gas infrastructure disruptions (such as compressor outages).
The Henry Hub price trended down during November and December as the United States experienced warmer-than-normal temperatures. Natural gas production increased to near pre-pandemic highs, allowing storage stocks to rebuild to near their five-year (2017-2021) average levels, even as LNG exports remained relatively high. After reaching a low for the winter heating season of $3.30/MMBtu on December 27, the Henry Hub price then rose throughout January to a recent high of $6.44/MMBtu. Temperatures cooled to below normal in mid-January and early February, and storage stocks fell back below their five-year average. Prices at the Henry Hub have since fallen in response to a more moderate weather forecast and anticipated decline in heating demand. In addition, concerns that an abnormally cold weather event in early February would cause significant production disruptions, like in February 2021, have passed.
Two regions have experienced significant, sustained swings in natural gas prices since the start of November, caused in part by fluctuations in the weather and the resulting impact on heating demand. Especially cold temperatures for most of January and early February, along with other factors, had a particularly strong effect on natural gas prices at the Algonquin Citygate – a major pricing point for natural gas delivered to New England, which relies on natural gas for space heating more than most other regions. Natural gas spot prices at Algonquin Citygate have exceeded $20.00/MMBtu on 18 days since November 1 in response to cold weather and other contributing factors. The Algonquin Citygate price has ranged from a low of $3.50/MMBtu to a high of $28.04/MMBtu, and it has averaged $11.28/MMBtu since November 1.
In Southern California, prices at SoCal Citygate have ranged from a low of $3.78/MMBtu to a high of $8.93/MMBtu since the beginning of November. The spot price moved from near the lower end of its range to the higher end as warmer-than-normal weather in November gave way to colder-than-normal weather in December and into the start of January. As HDDs fell to below-normal levels in mid-January, the price fell again, then rose briefly in early February in response to a return to above-normal HDDs. The price at SoCal Citygate has also been affected by supply constraints resulting from the outage on the El Paso Natural Gas (EPNG) pipeline Line 2000 segment, which has reduced the ability to transport natural gas into the region during periods of peak demand.
Overview:
(For the week ending Wednesday, February 23, 2022)
- Spot Prices: Natural gas spot prices rose at most locations this report week (Wednesday, February 16 to Wednesday, February 23). The Henry Hub spot price rose from $4.39 per million British thermal units (MMBtu) last Wednesday to $4.57/MMBtu yesterday.
- International Spot Prices: International natural gas spot prices were mixed this report week. Bloomberg Finance, L.P. reports that swap prices for liquefied natural gas (LNG) cargos in East Asia for the balance of February fell $0.43 to a weekly average of $24.39/MMBtu from $24.82/MMBtu last week. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead prices rose $1.26 to a weekly average of $25.72/MMBtu, bringing the TTF price back above the price in East Asia. In the same week last year (week ending February 24, 2021), prices in East Asia and at TTF were $6.29/MMBtu and $5.80/MMBtu, respectively.
- Futures: The price of the March 2022 NYMEX contract decreased 9.4 cents, from $4.717/MMBtu last Wednesday to $4.623/MMBtu yesterday. The price of the 12-month strip averaging March 2022 through February 2023 futures contracts climbed 1.6 cents to $4.742/MMBtu.
- Storage: The net withdrawals from working gas totaled 129 billion cubic feet (Bcf) for the week ending February 18. Working natural gas stocks totaled 1,782 Bcf, which is 10% lower than the year-ago level and 11% lower than the five-year (2017–2021) average for this week.
- NGPLs: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 55 cents/MMBtu, averaging $11.73/MMBtu for the week ending February 23. Ethane prices rose 6%, which is less than the 13% increase in the natural gas prices at the Houston Ship Channel. The ethane premium to natural gas decreased by 17 cents/MMBtu (9%) to $1.67/MMBtu. Propane prices rose 9%, while the average weekly Brent crude oil price remained relatively unchanged. The propane discount to crude oil narrowed by 45%, from $2.63/MMBtu to $1.45/MMBtu. Normal butane and isobutane prices rose 2% and the natural gasoline prices fell 1%.
- Rigs: According to Baker Hughes, for the week ending Tuesday, February 15, the natural gas rig count increased by 6 to 124 rigs. The largest gain was in the Haynesville (five rigs), followed by the Eagle Ford (two rigs), and the Marcellus and Arkoma Woodford (each adding one rig). The loss of three rigs in other basins offset the increase to result in a net gain of six rigs. The number of oil-directed rigs increased by 4 to 520 rigs. The Permian Basin had the largest gain, five rigs. Smaller additions and losses in other basins resulted in a net gain of four rigs. The total rig count now stands at 645, the highest level since April 3, 2020, and 248 rigs more than last year at this time.
Prices/Supply/Demand:
Prices on the Gulf Coast rise even as warm weather is forecast to continue. This report week (Wednesday, February 16 through Wednesday, February 23), the Henry Hub spot price rose 18 cents from $4.39/MMBtu last Wednesday to $4.57/MMBtu yesterday. Prices across much of the Southeast also rose. According to reports by IHS Markit, natural gas consumption for electricity generation in South Texas increased by almost 0.3 Bcf/d (10%) this report week as temperatures along the Texas Gulf Coast were warmer than normal. On Monday, the temperature reached a high of 83°F in Houston, Texas.
Prices in the Midwest rise slightly with cooler temperatures. At the Chicago Citygate, the price increased 44 cents from $4.32/MMBtu last Wednesday to $4.76/MMBtu yesterday. IHS Markit reports Mid-Continent natural gas consumption increased 0.6 Bcf/d (2%) to 24.1 Bcf/d from a week ago. Consumption in the residential and commercial sectors accounted for 0.4 Bcf/d of the increase, while the power generation sector accounted for the remainder. Temperatures in the Chicago area averaged 27°F, or 3°F below normal for the week, leading to 265 HDDs, or 16 more HDDs than the last report week.
Prices rise in the West as temperatures fall. The price at PG&E Citygate in Northern California rose 74 cents, up from $4.81/MMBtu last Wednesday to $5.55/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $1.45 from $4.36/MMBtu last Wednesday to $5.81/MMBtu yesterday. Prices in major supply regions also increased week over week. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, rose $1.32 from $4.13/MMBtu last Wednesday to $5.45/MMBtu yesterday. The price at Sumas on the Canada-Washington border, the main pricing point for natural gas in the Pacific Northwest, rose $1.44 from $4.01/MMBtu last Wednesday to $5.45/MMBtu yesterday. IHS Markit reports total consumption across the West rose by almost 1.9 Bcf/d (21%), with 1.5 Bcf/d attributed to increased consumption by the residential and commercial sectors. Over half of the increase in residential and commercial demand was in California, where it increased 0.9 Bcf/d (41%) this report week. In the Pacific Northwest, residential and commercial consumption increased by 0.4 Bcf/d (37%). NOAA reports temperatures in downtown Los Angeles averaged 56°F this report week, which led to 40 more HDDs than last week. In Seattle, Washington, temperatures averaged 40°F, almost 4°F lower than normal, leading to 37 more HDDs this report week than last week. Kinder Morgan, operator of the EPNG system, issued a preliminary March maintenance schedule showing Line 2000 maintenance through at least the end of the month. The pipeline operator’s updated force majeure statement on the outage states that “EPNG does not have an exact timeframe for bringing Line 2000 back to full commercial service.”
Prices in the Northeast rise with forecasts of another winter storm. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $10.96 from $4.13/MMBtu last Wednesday to $15.09/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 98 cents from $3.79/MMBtu last Wednesday to $4.77/MMBtu yesterday. Although daily temperatures in the Northeast were above average compared with the previous report week, they remained variable this week. New York City recorded a high of 68°F at the beginning and at the end of this report week, but in the middle of the week, the temperature reached a daily high of only 36°F. Daily natural gas consumption has been volatile as a result of the fluctuating temperatures; consumption increased 15% from 17.4 Bcf/d ahead of last weekend, according to IHS Markit. On a week-over-week basis, IHS Markit reports average consumption declined 4.0 Bcf/d (15%) to 23.4 Bcf/d from a week ago. Oil-fired electricity generation fell to zero this week as natural gas-fired electricity generation increased.
Prices in the Appalachia production region increase in advance of cooler weather forecast for the region. The Tennessee Zone 4 Marcellus spot price increased 63 cents from $3.70/MMBtu last Wednesday to $4.33/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 50 cents from $3.67/MMBtu last Wednesday to $4.17/MMBtu yesterday. According to IHS Markit, natural gas production in the Appalachian Basin was essentially unchanged from last week, averaging 33.3 Bcf/d this week. Consumption was down 1.7 Bcf/d (14%) to 10.4 Bcf/d week over week after averaging 12.5 Bcf/d in the early part of the report week. Average temperatures swung markedly in the region this week. The daily average temperature in the Pittsburgh area was 5°F below normal on February 18 and rose to 21°F above normal on February 22. NOAA forecasts another winter storm for the region ahead of the weekend.
Prices in the Permian production region increase in line with other regions as winter weather returns to a large portion of the United States. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 46 cents this report week, from $3.93/MMBtu last Wednesday to $4.39/MMBtu yesterday. The Waha Hub traded 18 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 46 cents below the Henry Hub price. Prices in West Texas increased from a week ago as another winter storm swept through the area, bringing with it colder-than-normal temperatures, freezing rain, and high winds. After averaging 15.4 Bcf/d for most of the report week, production in the Permian Basin declined 0.7 Bcf/d (5%) by the end of the report week, according to IHS Markit.
U.S. total natural gas supply declines slightly this week. Average total supply of natural gas fell this report week by 0.6% (0.6 Bcf/d) compared with the previous report week, according to data from IHS Markit. Dry natural gas production decreased by 0.5% (0.5 Bcf/d) compared with the previous report week, and average net imports from Canada were essentially flat at 5.8 Bcf/d this week.
U.S. total consumption of natural gas falls slightly this week. The total consumption of natural gas in the United States fell by 1.6% (1.4 Bcf/d) to 90.5 Bcf/d compared with the previous report week, according to data from IHS Markit. Consumption in the residential and commercial sectors declined the most, decreasing 4.6% (1.9 Bcf/d). Temperatures across the United States were mixed this report week, with above-average daytime highs in the eastern parts of the country and lower-than-average temperatures in the western and northern parts, according to NOAA. Industrial sector consumption also decreased by 1.1% (0.3 Bcf/d) this report week. Natural gas consumed for power generation climbed by 2.7% (0.7 Bcf/d) week over week. Natural gas exports to Mexico increased 1.6% (0.1 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.9 Bcf/d, or 0.9 Bcf/d lower than last week.
U.S. LNG exports are down by five vessels this week from last week. Eighteen LNG vessels (six from Sabine Pass, five from Corpus Christi, four from Cameron, and three from Freeport) with a combined LNG-carrying capacity of 67 Bcf departed the United States between February 17 and February 23, 2022, according to shipping data provided by Bloomberg Finance, L.P. Loadings may have been affected this week by fog and winter weather conditions that caused piloting services to be suspended for several days on the Sabine Pass and Lake Charles (the location of Cameron LNG) waterways.
Storage:
The net withdrawals from storage totaled 129 Bcf for the week ending February 18, compared with the five-year (2017–2021) average net withdrawals of 166 Bcf and last year's net withdrawals of 324 Bcf during the same week. Working natural gas stocks totaled 1,782 Bcf, which is 214 Bcf lower than the five-year average and 209 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 107 Bcf to 155 Bcf, with a median estimate of 127 Bcf.
The average rate of withdrawals from storage is 6% 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 8.1 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,452 Bcf on March 31, which is 214 Bcf lower than the five-year average of 1,666 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, 17-Feb |
Fri, 18-Feb |
Mon, 21-Feb |
Tue, 22-Feb |
Wed, 23-Feb |
|---|---|---|---|---|---|
| Henry Hub | 4.57 | 4.60 | HOLIDAY | 4.48 | 4.57 |
| New York | 4.55 | 4.53 | HOLIDAY | 3.93 | 4.77 |
| Chicago | 4.46 | 4.35 | HOLIDAY | 4.51 | 4.76 |
| Cal. Comp. Avg.* | 4.58 | 4.66 | HOLIDAY | 5.09 | 5.54 |
| Futures ($/MMBtu) | |||||
| March Contract | 4.486 | 4.431 | HOLIDAY | 4.498 | 4.623 |
| April Contract | 4.430 | 4.377 | HOLIDAY | 4.461 | 4.593 |
| *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: (2/17/22 - 2/23/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 107.5 |
108.0 |
80.0 |
| Dry production | 94.6 |
95.1 |
72.4 |
| Net Canada imports | 5.8 |
5.8 |
8.1 |
| LNG pipeline deliveries | 0.2 |
0.3 |
0.6 |
| Total supply | 100.5 |
101.2 |
81.2 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (2/17/22 - 2/23/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 90.5 |
91.9 |
104.9 |
| Power | 27.1 |
26.4 |
28.6 |
| Industrial | 24.4 |
24.7 |
23.8 |
| Residential/commercial | 39.0 |
40.8 |
52.4 |
| Mexico exports | 5.5 |
5.4 |
4.1 |
| Pipeline fuel use/losses | 7.1 |
7.2 |
6.5 |
| LNG pipeline receipts | 11.9 |
12.9 |
5.3 |
| Total demand | 115.1 |
117.4 |
120.8 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, February 15, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 520 |
0.8% |
70.5% |
| Natural gas rigs | 124 |
5.1% |
36.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, February 15, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 25 |
-10.7% |
4.2% |
| Horizontal | 589 |
2.6% |
65.0% |
| Directional | 31 |
-6.1% |
93.8% |
| 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 | 2022-02-18 |
2022-02-11 |
change |
|
| East | 396 |
435 |
-39 |
|
| Midwest | 450 |
496 |
-46 |
|
| Mountain | 105 |
114 |
-9 |
|
| Pacific | 176 |
177 |
-1 |
|
| South Central | 655 |
689 |
-34 |
|
| Total | 1,782 |
1,911 |
-129 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (2/18/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 433 |
-8.5 |
428 |
-7.5 |
|
| Midwest | 520 |
-13.5 |
515 |
-12.6 |
|
| Mountain | 125 |
-16.0 |
115 |
-8.7 |
|
| Pacific | 222 |
-20.7 |
191 |
-7.9 |
|
| South Central | 692 |
-5.3 |
747 |
-12.3 |
|
| Total | 1,991 |
-10.5 |
1,996 |
-10.7 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Feb 17) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 239 |
-21 |
-31 |
0 |
0 |
0 |
||
| Middle Atlantic | 229 |
-19 |
-41 |
0 |
0 |
0 |
||
| E N Central | 263 |
-5 |
-111 |
0 |
0 |
0 |
||
| W N Central | 288 |
16 |
-184 |
0 |
0 |
0 |
||
| South Atlantic | 142 |
-19 |
-33 |
6 |
-1 |
-10 |
||
| E S Central | 137 |
-23 |
-109 |
0 |
-1 |
0 |
||
| W S Central | 89 |
-20 |
-193 |
3 |
-1 |
3 |
||
| Mountain | 187 |
-15 |
-79 |
0 |
-1 |
0 |
||
| Pacific | 73 |
-29 |
-50 |
0 |
0 |
0 |
||
| United States | 186 |
-14 |
-91 |
1 |
0 |
-1 |
||
|
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 Feb 17, 2022
Source: National Oceanic and Atmospheric Administration Note: Image is not available.
Deviation between average and normal (°F)
7-day mean ending Feb 17, 2022
Source: National Oceanic and Atmospheric Administration Note: Image is not available.
