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Natural Gas Weekly Update

for week ending June 16, 2021   |  Release date:  June 17, 2021   |  Next release:  June 24, 2021   |   Previous weeks


JUMP TO: In The News | Overview | Prices/Supply/Demand | Storage

In the News:

Reduced pressure on the Texas Eastern Transmission limits southbound capacity from the Appalachia Basin

On June 1, the Texas Eastern Transmission (TETCO) pipeline reduced pressure by 20% between the Uniontown compressor station in southwest Pennsylvania and the Kosciusko compressor station in central Mississippi. The pressure was reduced because the Pipeline and Hazardous Materials Safety Administration (PHMSA) declined to renew its waiver of previously imposed pressure reductions.

The initial PHMSA order to reduce pressure was related to an explosion on TETCO’s Line 15 in August 2019. PHMSA amended the order in June 2020 following an explosion on Line 10, which runs parallel to Line 15. By December 2020, PHMSA gave TETCO temporary permission to return Lines 10, 15, and 25 (which also runs parallel to Line 15) to full pressure under the condition that TETCO had to reapply for the waiver every 90 days. PHMSA denied the most recent request, and TETCO complied by reducing pressure on Lines 10 and 15. According to data from TETCO, the reduced pressure has lowered southbound capacity from about 1.8 billion cubic feet per day (Bcf/d) on May 31 to 1.1 Bcf/d on June 2, a 39% decrease.

The TETCO pipeline system has two main segments going from the Northeast to the Gulf Coast that diverge at the Berne compressor station in eastern Ohio. The first segment is the 30-inch system (consisting of Lines 10, 15, and 25), which reaches the Gulf Coast via Kentucky, Tennessee, Alabama, Mississippi, and Louisiana. The second segment is the 24-inch system, which flows through Indiana, Illinois, Missouri, Arkansas, and Texas and has been largely unaffected by the pressure reductions.

Following the TETCO capacity reduction, the difference in prices between the Henry Hub in Louisiana and price points in the Northeast—referred to as basis—has widened during June, and prices in southwest Pennsylvania (the primary supply region for TETCO) have become less responsive to regional supply and demand dynamics. The price basis between the Henry Hub and Eastern Gas South in southwest Pennsylvania ended May at -63¢ per million British thermal units (MMBtu), but has been under -$1.00/MMBtu in June.

However, other Northeast price points increased during the warmer-than-normal temperatures that affected the Northeast during the first two weeks of June, reducing the difference between northeastern points and the Henry Hub. This heat wave increased power demand for cooling, leading to higher natural gas consumption for power generation. The basis between the Henry Hub and Transco Zone 6 in New York City went from -48¢/MMBtu on May 28 (the last trading day in May) to -$1.02/MMBtu on June 15, with a high of -12¢/MMBtu on June 7. Similarly, the basis between the Henry Hub and Texas Eastern M-3 Delivery in the eastern Pennsylvania, New Jersey, and New York area went from -50¢/MMBtu on May 28 to -$1.09/MMBtu on June 15, with a high of -31¢/MMBtu on June 4.

Enbridge states that they “anticipate that the [30-inch system] will be returned [to normal operating pressure] by the end of the third quarter at the earliest.

Overview:

(For the week ending Wednesday, June 16, 2021)

  • Natural gas spot prices rose at most locations this report week (Wednesday, June 9 to Wednesday, June 16) in response to persistent extreme heat across the western United States and the resulting demand for electric power for air conditioning. The Henry Hub spot price rose from $3.10 per million British thermal units (MMBtu) last Wednesday to $3.17/MMBtu yesterday.
  • The price of the July 2021 NYMEX contract increased 12¢ from $3.129/MMBtu last Wednesday to $3.251/MMBtu yesterday. The price of the 12-month strip averaging July 2021 through June 2022 futures contracts climbed 10¢/MMBtu to $3.204/MMBtu.
  • The net injections to working gas totaled 16 billion cubic feet (Bcf) for the week ending June 11. Working natural gas stocks totaled 2,427 Bcf, which is 16% lower than the year-ago level and 5% lower than the five-year (2016–2020) average for this week.
  • The natural gas plant liquids composite price at Mont Belvieu, Texas, the main pricing and storage hub for hydrocarbon gas liquids on the Gulf Coast, rose by 20¢/MMBtu and averaged $8.46/MMBtu for the week ending June 16. Ethane prices rose 4% following the rise in natural gas prices at the Houston Ship Channel, which increased 6%. Prices for propane and isobutane both increased by 3% following the 3% increase in Brent crude oil. Normal butane and natural gasoline prices rose 1%.
  • According to Baker Hughes, for the week ending Tuesday, June 8, the natural gas rig count decreased by 1 to 96, 7 rigs fewer than the highest natural gas rig count so far this year, which was reported for the week ending on May 7. The number of oil-directed rigs rose by 6 to 365, 199 more than for the same week last year. The largest reported weekly gains were in Wyoming, where the oil-directed rig count rose by 3 to 6 rigs. The Permian Basin gained 4 rigs, 2 each in Texas and New Mexico, with offsetting losses elsewhere. The total rig count increased by 5, and it now stands at 461, the highest total since late April 2020.

more summary data

Prices/Supply/Demand:

Gulf Coast prices rise as a heat advisory and strong power generation demand pushes natural gas consumption above seasonal averages. This report week (Wednesday, June 9 to Wednesday, June 16), the Henry Hub spot price rose 7¢ from $3.10/MMBtu last Wednesday to $3.17/MMBtu yesterday after reaching a weekly high of $3.30/MMBtu on Tuesday. Prices reported for the Houston Ship Channel rose 18¢ from $3.01/MMBtu last Wednesday to $3.19/MMBtu yesterday, which also reached its peak on Tuesday at $3.34/MMBtu. The Electric Reliability Council of Texas (ERCOT) began issuing notices on Sunday advising of potential capacity shortages. Electricity demand for air conditioning was forecast to rise to record levels for June amid higher-than-average generator outages that forced 11,000 megawatts (MW) of generation offline. The daily high temperature in both Dallas and Houston reached 99°F on Monday, 7°F and 8°F above normal, respectively. Temperatures in both cities remained in the high 90’s through yesterday, resulting in elevated demand for air conditioning and high demand for power generation. IHS Markit reported electricity generation demand in Texas averaged 5.8 billion cubic feet per day (Bcf/d) this report week, more than 1.0 Bcf/d above last week. Natural gas consumption for power generation exceeded 6.0 Bcf/d on Sunday and Monday—the highest daily totals since mid-February, when Texas power demand surged during the winter storm.

Record-breaking temperatures across the West drive natural gas demand, and prices, higher. Current drought conditions in the West have limited the ability of hydroelectric generation to increase output, resulting in elevated demand for natural-gas fired generation. IHS Markit estimates power demand across the West exceeded 6.2 Bcf/d yesterday, the highest level for mid-June since 2015. The price at PG&E Citygate in Northern California rose 82¢, up from $3.87/MMBtu last Wednesday to a weekly high of $4.69/MMBtu yesterday. Prices at Opal in Southwest Wyoming, the main trading point for natural gas in the Rocky Mountain region and the origin point for deliveries into the California market through the Ruby Pipeline, rose 52¢ from $2.86/MMBtu last Wednesday to $3.38/MMBtu yesterday after reaching $3.47/MMBtu on Monday. Temperatures in Salt Lake City, 100 miles west of Opal and connected to the Opal hub through the Kern River Transmission pipeline, reached 103°F on Monday, and 107°F on Tuesday, exceeding by 5°F the previous daily record high of 102°F set in 1974. Supply into the Northwest was also impaired by a compressor outage on the Gas Transmission Northwest (GTN) pipeline, which receives natural gas at the British Columbia/Idaho Kingsgate border crossing for delivery into the Northwest. TC Energy, operator of the GTN pipeline, declared a force majeure on Tuesday due to a compressor outage, reducing capacity by approximately 200 million cubic feet per day (MMcf/d) during a time of high demand in the region.

The price at SoCal Citygate in Southern California increased $2.16 from $3.50/MMBtu last Wednesday to $5.66/MMBtu yesterday after peaking at $8.24/MMBtu on Monday. The temperature at Palm Springs, California, reached a new record high at 120°F on Tuesday, 4°F above the record set in 1961. SoCalGas reports withdrawals from natural gas storage for two consecutive days, Tuesday and Wednesday, for the first time in June since 2017.

Midwest prices rise as high air conditioning demand raises demand for natural gas-fired power generation in the region. At the Chicago Citygate, the price increased 4¢ from $3.07/MMBtu last Wednesday to $3.11/MMBtu yesterday. Prices at Chicago Citygate rose to a high of $3.21/MMBtu on Monday, when the daily high temperature in the city rose to 82°F. IHS Markit estimated natural gas consumption for power generation in the Midwest rose above 3.6 Bcf/d.

Northeast prices decline as temperatures moderate from last week’s well-above-normal levels. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 26¢ from $2.62/MMBtu last Wednesday to $2.36/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price remained unchanged week over week at $2.30/MMBtu. Both the Algonquin Citygate and the Transcontinental Pipeline Zone 6 pricing points reported weekly lows on Friday of $2.12/MMBtu and $2.06/MMBtu, respectively. Temperatures moderated in both Boston and New York, falling into the 70’s from the 90’s last week. The daily high in Boston was 70°F on Monday and rose to 77°F yesterday, on par with normal. Temperatures in New York City also remained moderate, averaging in the 70’s, with the daily high for the week on Tuesday at 80°F, on par with normal for the day.

Prices in the Appalachia Basin production region remain depressed due to continuing impairment to takeaway capacity. The Tennessee Zone 4 Marcellus spot price decreased 2¢ from $1.94/MMBtu last Wednesday to $1.92/MMBtu yesterday. The price at Eastern Gas South (formerly known as Dominion South until June 1, 2021) in Southwestern Pennsylvania rose 11¢ from $2.00/MMBtu last Wednesday to $2.11/MMBtu yesterday. Both the Tennessee Zone 4 and the Eastern Gas South pricing points reported their lowest prices of the report week last Thursday, at $1.83/MMBtu and $2.01/MMBtu, respectively. You can read more about this takeaway capacity impairment in the feature article in this report.

The price in the Permian Basin production region in West Texas rises in response to increased demand across the West. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 26¢/MMBtu from $2.78/MMBtu last Wednesday to $3.04/MMBtu yesterday. The discount at the Waha Hub relative to the Henry Hub decreased from 32¢/MMBtu last Wednesday to 13¢/MMBtu yesterday.

Natural gas production declines to 92.8 Bcf/d, from last week’s average of 93.3 Bcf/d. According to data from IHS Markit, dry natural gas production decreased by 0.5% compared with the previous report week to average 92.8 Bcf/d, a 0.5 Bcf/d decline week over week. Average net imports from Canada increased week over week by 8.6% from 4.6 Bcf/d to 5.0 Bcf/d, the highest weekly average since the third week of April. Average total supply of natural gas fell by 0.1% compared with the previous report week.

Demand remains fairly flat as high temperatures and increased power generation demand in the West offset declines in power generation demand in the East. Temperatures across the Lower 48 states were mixed this report week. Temperatures in the West set records and drove demand for air conditioning higher; however, temperatures in the Northeast were moderate. Total U.S. consumption of natural gas fell by 0.1% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 2.3% week over week from a weekly average of 35.5 Bcf/d last week to 36.3 Bcf/d this report week; however, the regional distribution of demand shifted rapidly from the East to the West due to temperature changes discussed above. Industrial sector consumption was relatively flat, decreasing 0.3% week over week from 20.3 Bcf/d to 20.2 Bcf/d. In the residential and commercial sectors, consumption continued to decline, falling by 9.1% this week after a 25.8% decline last week, as demand for space heating diminishes. Natural gas exports to Mexico increased 4.6% to 6.8 Bcf/d, a new weekly average record. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 9.4 Bcf/d, or 0.08 Bcf/d higher than last week.

U.S. LNG exports increase week over week. Eighteen LNG vessels (four each from Sabine Pass, Freeport and Corpus Christi, and three each from Cove Point and Cameron) with a combined LNG-carrying capacity of 65 Bcf departed the United States between June 10 and June 16, 2021, according to shipping data provided by Bloomberg Finance, L.P.

Storage:

The net injections into storage totaled 16 Bcf for the week ending June 11, compared with the five-year (2016–2020) average net injections of 87 Bcf and last year's net injections of 86 Bcf during the same week. Working natural gas stocks totaled 2,427 Bcf, which is 126 Bcf lower than the five-year average and 453 Bcf lower than last year at this time. This week’s working gas total reflects reclassifications from working to base gas that reduced working gas inventories by 51 Bcf in the Pacific region, for the week ending June 11. Analysis of the impacts of this reclassification will appear in next week’s Natural Gas Weekly Update.

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 58 Bcf to 81 Bcf with a median estimate of 71 Bcf.

The average rate of injections into storage is 13% 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 8.2 Bcf/d for the remainder of the refill season, the total inventory would be 3,593 Bcf on October 31, which is 126 Bcf lower than the five-year average of 3,719 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:



Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
10-Jun
Fri,
11-Jun
Mon,
14-Jun
Tue,
15-Jun
Wed,
16-Jun
Henry Hub
3.09
3.21
3.28
3.30
3.17
New York
2.10
2.06
2.30
2.29
2.30
Chicago
3.07
3.16
3.21
3.21
3.11
Cal. Comp. Avg.*
3.26
3.66
4.83
4.24
4.21
Futures ($/MMBtu)
July contract
3.149
3.296
3.352
3.240
3.251
August contract
3.166
3.311
3.367
3.256
3.271
*Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg.
Source: NGI's Daily Gas Price Index
Natural gas futures prices
Natural gas liquids spot prices


U.S. natural gas supply - Gas Week: (6/10/21 - 6/16/21)
Average daily values (billion cubic feet)
this week
last week
last year
Marketed production
104.7
105.5
99.5
Dry production
92.8
93.3
88.2
Net Canada imports
5.0
4.6
3.6
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
97.9
98.0
91.9

Source: IHS Markit
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: (6/10/21 - 6/16/21)
Average daily values (billion cubic feet)
this week
last week
last year
U.S. consumption
64.5
64.5
61.6
    Power
36.3
35.5
32.3
    Industrial
20.2
20.3
20.3
    Residential/commercial
7.9
8.7
9.0
Mexico exports
6.8
6.5
5.4
Pipeline fuel use/losses
6.3
6.3
6.0
LNG pipeline receipts
9.4
9.4
3.9
Total demand
87.0
86.7
76.9

Source: IHS Markit
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, June 08, 2021
Change from
 
last week
last year
Oil rigs
365
1.7%
83.4%
Natural gas rigs
96
-1.0%
23.1%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, June 08, 2021
Change from
 
last week
last year
Vertical
17
6.3%
54.5%
Horizontal
420
1.2%
70.7%
Directional
24
-4.0%
9.1%
Source: Baker Hughes Co.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2021-06-11
2021-06-04
change
East
461
445
16
Midwest
570
547
23
Mountain
 165
 160
5
Pacific
   236 C
276
-40
South Central
995
983
12
Total
2,427 C
2,411
16
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report
C=Reclassification
Note: Reclassifications from working gas to base gas resulted in decreased working gas stocks of 51 Bcf in the Pacific region for the week ending June 11, 2021. The implied flow for the week is an increase of 67 Bcf to working gas stocks.
Working gas in underground storage
Historical comparisons
Year ago
(6/11/20)
5-year average
(2016-2020)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
583
-20.9
503
-8.3
Midwest
684
-16.7
581
-1.9
Mountain
155
6.5
153
7.8
Pacific
289
-18.3
270
-12.6
South Central
1,170
-15.0
1,046
-4.9
Total
2,880
-15.7
2,553
-4.9
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Jun 10)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
1
-21
-8
60
53
38
Middle Atlantic
0
-15
-2
72
54
36
E N Central
0
-19
-2
73
46
18
W N Central
0
-17
-1
83
48
8
South Atlantic
0
-4
0
94
29
7
E S Central
0
-3
0
67
9
-21
W S Central
0
0
0
96
6
-22
Mountain
4
-26
-18
60
18
13
Pacific
24
4
5
10
-7
-8
United States
5
-11
-2
68
27
8
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-day mean ending Jun 10, 2021

Mean Temperature (F) 7-Day Mean ending Jun 10, 2021

Source: National Oceanic and Atmospheric Administration

Deviation between average and normal (°F)

7-day mean ending Jun 10, 2021

Mean Temperature Anomaly (F) 7-Day Mean ending Jun 10, 2021

Source: National Oceanic and Atmospheric Administration