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Natural Gas Weekly Update

for week ending August 10, 2022   |  Release date:  August 11, 2022   |  Next release:  August 18, 2022   |   Previous weeks

JUMP TO: Prices | Supply and Demand | Liquefied Natural Gas (LNG) | Rig Count | Storage | Other Market Drivers

In the News:

Natural gas price volatility reached an all-time high in first-quarter 2022

Natural gas price volatility—a measure of how much daily prices change—reached the highest levels in 20 years in the first quarter of 2022 in the United States. The 30-day historical volatility of U.S. natural gas prices, based on the Henry Hub front-month futures price, averaged 179% in February compared with the five-year (2017–21) average of 48%.

Historical volatility—a measure of how much the daily closing price for a commodity changes during a specific time in the past—was lower in July, when natural gas prices were relatively higher than in the first quarter. In July, the Henry Hub front-month futures price averaged $7.19 per million British thermal units (MMBtu) compared with an average of $4.46/MMBtu in February. In the first quarter of 2022, natural gas price volatility averaged 124% compared with 75% in the second quarter.

Periods of high price volatility can occur as a result of increased uncertainty surrounding material changes in market conditions that affect natural gas supply and demand. Events that could contribute to changing market conditions include production freeze-offs, storms, unplanned pipeline maintenance and outages, significant departures from normal weather, changes in the disposition of inventory levels, the availability of substitute fuels, the level of imports or exports, or other sudden changes in demand.

Volatility in the Henry Hub front-month futures price was particularly high during the first quarter of 2022. U.S. natural gas price volatility is typically higher during the first quarter because of space-heating demand for natural gas. Factors contributing to heightened volatility in the first three months of this year include weather-driven fluctuations in natural gas demand, a decrease in natural gas production from the end of 2021, declines in Lower 48 states’ working gas levels, and record U.S. LNG exports to Europe to help offset reduced natural gas supplies from Russia.

Natural gas price volatility fell to an average 56% in April but has risen in subsequent months, averaging 109% in July. Contributing to this increase is both warmer-than-normal weather and increased domestic supply following the fire and subsequent outage of the Freeport LNG export terminal on June 8, 2022.

The temporary shutdown of the Freeport LNG terminal resulted in demand for feed gas declining about 2 billion cubic feet per day (Bcf/d) and generated a potential surplus in the domestic market. The immediate market reaction to the Freeport LNG outage was a decline in the Henry Hub futures price, which fell by 39% from June 10 to June 30. In July, however, the higher-than-normal temperatures across much of the United States resulted in strong natural gas demand in the electric power sector, which absorbed much of the Freeport LNG-related surplus and kept natural gas inventories from rising faster. As a result, natural gas futures prices increased 52% from June 30 to July 29 amid high price volatility.

Market Highlights:

(For the week ending Wednesday, August 10, 2022)

Prices

  • Henry Hub spot price: The Henry Hub spot price rose 6 cents from $7.83 per million British thermal units (MMBtu) last Wednesday to $7.89/MMBtu yesterday.
  • Henry Hub futures prices: The price of the September 2022 NYMEX contract decreased 6 cents, from $8.266/MMBtu last Wednesday to $8.202/MMBtu yesterday. The price of the 12-month strip averaging September 2022 through August 2023 futures contracts declined 2 cents to $6.732/MMBtu.
  • Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, August 3 to Wednesday, August 10). Price increases ranged from 6 cents at Henry Hub to 83 cents at SoCal Citygate in Southern California. Algonquin Citygate and Transco Zone 6, among the few regions where prices decreased week over week, fell by 89 cents and 68 cents, respectively.
    • The price at PG&E Citygate in Northern California rose 36 cents, up from $8.78/MMBtu last Wednesday to $9.14/MMBtu yesterday. The price at SoCal Citygate in Southern California increased 83 cents from $9.38/MMBtu last Wednesday to $10.21/MMBtu yesterday. In northern California, PG&E’s maintenance schedule includes work on the Redwood pipeline and Buckeye station beginning August 6 through the end of the month. The Redwood pipeline delivers natural gas from Malin, Oregon, to the San Francisco Citygate. PG&E expects available pipeline capacity to be between 70% and 90% for the next few weeks. In the Southwest, El Paso Natural Gas Company reported pipeline remediation on Line 1100 from Wenden, Arizona, to Ehrenberg, Arizona, one of the main delivery points into the SoCalGas service territory, beginning August 8 through at least the end of the month. In addition to the 450 million cubic feet per day (MMcf/d) currently unavailable with the on-going repair of Line 2000, this remediation reduces pipeline capacity by close to another 180 MMcf/d.
    • At the Algonquin Citygate, which serves Boston-area consumers, the price went down 89 cents from the weekly high of $8.53/MMBtu last Wednesday to $7.64/MMBtu yesterday. The daily high temperature in the Boston area fell to 72°F yesterday, 5°F below normal, and temperatures are forecast to be close to seasonal normals over the weekend and into next week. During this report week, however, the daily high temperature reached 98°F four days out of seven. Natural gas consumption in the New England electric power sector increased 0.3 billion cubic feet per day (Bcf/d), or 17%, according to data from PointLogic. At the Transco Zone 6 trading point for New York City, the price decreased 68 cents from $8.11/MMBtu last Wednesday to $7.43/MMBtu yesterday. Similar to New England, New York City daily high temperatures were above 90°F for most of the report week and temperatures are expected to decline closer to normal levels.
    • The FGT Citygate spot price decreased $1.39 from $11.95/MMBtu last Wednesday to $10.56/MMBtu yesterday. The FGT Citygate price reflects deliveries into Florida via the Florida Gas Transmission pipeline. Despite three weeks of price declines of nearly $1.00 or more week over week, the FGT Citygate price remains elevated, and traded at a $2.67/MMBtu premium to Henry Hub yesterday. A constraint at Compressor Station 60 (CS 60) on William’s Transco pipeline, which serves the Gulf Coast and Southeast regions, continues to affect the region. CS 60 is approximately 25 miles north-northwest of Baton Rouge in Louisiana.

    Daily spot prices by region are available on the EIA website.

  • International futures prices: According to Bloomberg Finance, L.P., weekly average futures prices for liquefied natural gas (LNG) cargoes in East Asia increased 65 cents to a weekly average of $44.61/MMBtu, and natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, decreased 38 cents to a weekly average of $59.16/MMBtu.
  • Natural gas plant liquids prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 49 cents/MMBtu, averaging $10.90/MMBtu for the week ending August 10. Weekly average natural gas prices at the Houston Ship Channel fell 1%, while the price of ethane fell 4%, narrowing the ethane premium to natural gas by 26%. The price of ethylene rose 2%, widening the ethylene to ethane spread by 32%. Propane and normal butane prices fell 5% along with Brent crude oil, which also fell 5%, narrowing the propane discount to crude oil. The isobutane and natural gasoline prices fell 4% and 3%, respectively.
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Supply and Demand

  • Supply: According to data from PointLogic, the average total supply of natural gas fell by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.2% (0.2 Bcf/d) compared with the previous report week. Average net imports from Canada decreased by 6.0% (0.3 Bcf/d) from last week.
  • Demand: Total U.S. consumption of natural gas rose by 2.7% (1.9 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation climbed by 4.0% (1.7 Bcf/d) week over week as above normal temperatures in the Northeast increased demand for air conditioning. U.S. Industrial sector consumption increased by 0.6% (0.1 Bcf/d) week over week. In the residential and commercial sectors, consumption increased by 1.4% (0.1 Bcf/d). Natural gas exports to Mexico decreased 3.3% (0.2 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 10.8 Bcf/d, or 0.1 Bcf/d lower than last week.
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Liquefied Natural Gas (LNG)

  • Pipeline receipts: Natural gas deliveries to LNG export terminals in South Louisiana and South Texas were essentially flat this week at 7.4 Bcf/d and 2.3 Bcf/d, respectively. Natural gas deliveries to terminals along the East Coast decreased slightly, by less than 0.1 Bcf/d, to 1.0 Bcf/d. Deliveries to Calcasieu Pass in Louisiana were on average about 400 MMcf/d lower than last week, whereas deliveries to Sabine Pass, also in Louisiana, averaged about 300 MMcf/d higher than a week ago.
  • Vessels departing U.S. ports: Seventeen LNG vessels (eight from Sabine Pass, four Corpus Christi, three from Cameron, and one each from Calcasieu Pass and Cove Point) with a combined LNG-carrying capacity of 64 Bcf departed the United States between August 4 and August 10, according to shipping data provided by Bloomberg Finance, L.P.
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Rig Count

  • According to Baker Hughes, for the week ending Tuesday, August 2, the natural gas rig count increased by 4 rigs from a week ago to 161 rigs. All four rigs were added in unspecified producing regions. The number of oil-directed rigs decreased by 7 to 598 rigs. The Ardmore Woodford, DJ Niobrara, Granite Wash, and Williston each added one rig. The Cana Woodford dropped one rig, the Permian Basin dropped four rigs, and six rigs were dropped from unspecified producing regions. The total rig count now stands at 764 rigs.
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Storage

  • The net injections into storage totaled 44 Bcf for the week ending August 5, compared with the five-year (2017–2021) average net injections of 45 Bcf and last year's net injections of 44 Bcf during the same week. Working natural gas stocks totaled 2,501 Bcf, which is 338 Bcf (12%) lower than the five-year average and 268 Bcf (10%) 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 injections of 30 Bcf to 47 Bcf, with a median estimate of 40 Bcf.
  • The average rate of injections into storage is 5% lower than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 9.3 Bcf/d for the remainder of the refill season, the total inventory would be 3,307 Bcf on October 31, which is 338 Bcf lower than the five-year average of 3,645 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.

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Other Market Drivers

    Natural Gas Pipeline Company of America declared a force majeure at segment 26 of the Gulf Coast #3 main line, which runs from Cass County, Texas, to Montgomery County, Texas, from August 9 through August 12. The company is performing pipeline remediation work between Compressor Station 304 (CS 304) in Harrison County, Texas, and Compressor Station 303 (CS 303) in Angelina County, Texas, that results in a reduction of maximum operating capacity. Throughput capacity southbound through CS 303 is reduced and limited to no less than 79% of the design capacity of approximately 1.7 MMcf/d.

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See also:

Natural gas 30-day historical volatility (Jan 2012–Jul 2022)Data source: Bloomberg L.P.
Notes: Annualized percentage = the standard deviation for the previous 30 days of daily changes in the Henry Hub front-month futures price multiplied by the square root of 252 (number of trading days in a year) multiplied by 100. Percentages are averages for that period.
Henry Hub front-month natural gas futures price and historical volatility (Jan 2020–Jul 2022)
Data source: CME Group, Bloomberg L.P.
Note: Annualized percentage = the standard deviation for the previous 30 days of daily changes in the Henry Hub front-month futures price multiplied by the square root of 252 (number of trading days in a year) multiplied by 100.


Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
04-Aug
Fri,
05-Aug
Mon,
08-Aug
Tue,
09-Aug
Wed,
10-Aug
Henry Hub
8.37
8.19
7.77
7.88
7.89
New York
7.91
7.90
7.69
7.58
7.43
Chicago
7.87
7.86
7.46
7.71
7.79
Cal. Comp. Avg.*
9.02
8.75
8.79
9.17
8.93
Futures ($/MMBtu)
September contract
8.122
8.064
7.589
7.833
8.202
October contract
8.114
8.051
7.578
7.825
8.193
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.
Natural gas futures prices


U.S. natural gas supply - Gas Week: (8/4/22 - 8/10/22)
Average daily values (billion cubic feet)
this week
last week
last year
Marketed production
111.0
110.7
106.0
Dry production
98.1
97.9
93.7
Net Canada imports
5.2
5.6
4.6
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
103.4
103.5
98.3

Data source: PointLogic
Note: This table reflects any data revisions that may have occurred since the previous week's posting. Liquefied natural gas (LNG) pipeline deliveries represent natural gas sendout from LNG import terminals.

U.S. natural gas consumption - Gas Week: (8/4/22 - 8/10/22)
Average daily values (billion cubic feet)
this week
last week
last year
U.S. consumption
74.3
72.4
68.1
    Power
43.8
42.1
38.8
    Industrial
21.2
21.0
21.4
    Residential/commercial
9.4
9.2
7.8
Mexico exports
5.5
5.7
6.5
Pipeline fuel use/losses
6.8
6.7
6.4
LNG pipeline receipts
10.8
10.9
10.2
Total demand
97.4
95.6
91.2

Data source: PointLogic
Note: This table reflects any data revisions that may have occurred since the previous week's posting. Liquefied natural gas (LNG) pipeline receipts represent pipeline deliveries to LNG export terminals.

Natural gas supply


Weekly natural gas rig count and average Henry Hub
Rigs
Tue, August 02, 2022
Change from
 
last week
last year
Oil rigs
598
-1.2%
54.5%
Natural gas rigs
161
2.5%
56.3%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, August 02, 2022
Change from
 
last week
last year
Vertical
29
-9.4%
93.3%
Horizontal
698
0.1%
55.5%
Directional
37
-2.6%
37.0%
Data source: Baker Hughes Company


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2022-08-05
2022-07-29
change
East
564
549
15
Midwest
663
643
20
Mountain
 148
 147
1
Pacific
252
253
-1
South Central
874
865
9
Total
2,501
2,457
44
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
(8/5/21)
5-year average
(2017-2021)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
625
-9.8
647
-12.8
Midwest
738
-10.2
732
-9.4
Mountain
185
-20.0
181
-18.2
Pacific
241
4.6
272
-7.4
South Central
979
-10.7
1,007
-13.2
Total
2,769
-9.7
2,839
-11.9
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Aug 04)
 
HDDs
CDDs
Region
Current total
Deviation from normal
Deviation from last year
Current total
Deviation from normal
Deviation from last year
New England
0
-2
-7
69
25
54
Middle Atlantic
0
-3
-3
70
11
42
E N Central
1
-3
-4
57
1
24
W N Central
1
-2
-1
71
1
12
South Atlantic
0
0
0
109
12
15
E S Central
0
0
0
97
3
8
W S Central
0
0
0
143
17
20
Mountain
0
-2
0
80
3
-4
Pacific
0
-2
0
73
26
-4
United States
0
-2
-2
86
12
18
Data source: National Oceanic and Atmospheric Administration
Note: HDDs=heating degree days; CDDs=cooling degree days

   Average temperature (°F)


    7-day mean ending Aug 04, 2022

Mean Temperature (F) 7-Day Mean ending Aug 04, 2022

        Data source: National Oceanic and Atmospheric Administration

  Deviation between average and normal temperature (°F)


   7-day mean ending Aug 04, 2022

Mean Temperature Anomaly (F) 7-Day Mean ending Aug 04, 2022

        Data source: National Oceanic and Atmospheric Administration