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Natural Gas Weekly Update

for week ending May 5, 2021   |  Release date:  May 6, 2021   |  Next release:  May 13, 2021   |   Previous weeks


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

In the News:

Natural gas generation is lower compared with a year ago

In the first four months of 2021, natural gas-fired generation in the Lower 48 states averaged 3,394 gigawatthours (GWh) per day, according to data from our Hourly Electric Grid Monitor, a decline of nearly 7% compared with the same period a year ago. This year’s decline is the first year-over-year decline in natural gas generation during this period since 2017. The decline in natural gas-fired generation is a result of higher natural gas prices and increased competition from renewables. Total electricity generation during the period increased 6.6% compared with 2020, which is primarily attributable to colder winter weather.

In response to lower natural gas production and higher winter heating demand during the 2020–21 winter heating season (October–March) compared with the prior winter heating season, natural gas prices have risen considerably over the past year. Excluding the temporary, weather-driven price increase from February 16–19 that briefly led to record nominal natural gas prices, from January through April 2021 the natural gas price at the Henry Hub averaged $2.83 per million British thermal units (MMBtu). The Henry Hub price averaged $0.88/MMBtu more in 2021 than during the same period in 2020, when prices were very low amid a relatively warm 2019–20 winter. Higher natural gas prices have made natural gas-fired generation relatively less competitive compared with coal-fired generation, prompting natural gas-to-coal fuel switching. Coal-fired generation has increased nearly 40% in the first four months of 2021 compared with the same period in 2020, accounting for 23% of total generation, according to our recent Hourly Electric Grid Monitor data

Natural gas-fired generation has also been facing increased competition from renewable generation, primarily as a result of recent record-breaking capacity additions of wind and solar power plants. Between May 2020 and February 2021 (the most recent month for which we have data), 22.5 gigawatts (GW) of combined net wind and solar electric generating capacity additions (a 15% increase) have come online, and an additional 28.7 GW is planned to come online during the remainder of 2021, according to the latest Preliminary Monthly Electric Generator Inventory. During the same period, significantly less natural gas capacity came online, (4.8 GW), and an additional 3.8 GW of capacity is planned to come online during the remainder of 2021.

We expect declines in natural gas-fired generation to continue through 2022. According to April’s Short-Term Energy Outlook, we forecast natural gas-fired generation will decline 6.8% in 2021 and a further 2.3% in 2022.

Overview:

(For the week ending Wednesday, May 5, 2021)

  • Natural gas spot price movements were mixed this report week (Wednesday, April 28 to Wednesday, May 5), reflecting highly variable temperatures across the country at the end of the report week. The Henry Hub spot price rose from $2.93 per million British thermal units (MMBtu) last Wednesday to $2.97/MMBtu yesterday.
  • The May 2021 NYMEX contract expired last Wednesday at $2.925/MMBtu. The June 2021 contract price decreased to $2.938/MMBtu, down 2¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging June 2021 through May 2022 futures contracts declined 1¢/MMBtu to $2.977/MMBtu.
  • The net injections to working gas totaled 60 billion cubic feet (Bcf) for the week ending April 30. Working natural gas stocks totaled 1,958 Bcf, which is 15% lower than the year-ago level and 3% lower than the five-year (2016–2020) average for this week.
  • The natural gas plant liquids (NGPL) composite price at Mont Belvieu, Texas, rose by 46¢/MMBtu, averaging $7.66/MMBtu for the week ending May 5. NGPL prices are following crude oil prices higher. Average weekly Brent crude oil spot prices rose 4% week over week, to $68.09 per barrel (b), exceeding the $68.00/b level for only the second time this year. The price of natural gasoline, most closely correlated with crude oil, also rose 4% week over week. Elevated exports of propane, butane, and isobutane are supporting elevated prices of all three fuels, which rose by 9%, 6%, and 7%, respectively. Ethane prices rose 3% week over week, slightly faster than natural gas prices, which rose by 1% at the Henry Hub. Ethane price premium to natural gas at heat-value parity continues increasing, reaching 31% this week, from 18% in the first week of March.
  • According to Baker Hughes, for the week ending Tuesday, April 27, the natural gas rig count increased by 2 to 96. The number of oil-directed rigs fell by 1 for the second week in a row, to 342. Oil-directed rig losses were concentrated in the Permian basin, which lost three rigs in total (two in Texas, one in New Mexico), but were somewhat offset by gains elsewhere. The Permian Basin lost rigs two weeks in a row, after posting gains for 29 of the previous 30 weeks. The total rig count increased by 2, and it now stands at 440, the highest total in over a year.

more summary data

Prices/Supply/Demand:

Price movements across the country are mixed, reflecting variability in weather this report week (Wednesday, April 28 to Wednesday, May 5). The Henry Hub spot price rose 4¢ from $2.93/MMBtu last Wednesday to $2.97/MMBtu yesterday. Reflecting the high variability in this report week’s weather, Henry Hub prices fell to a low of $2.85 last Thursday and rose as high as $3.01/MMBtu on Tuesday. Temperature anomalies, related to a continuation of the polar vortex disruption that first emerged in mid-January, continue to move across the country and brought shifts of summer-time weather followed by temperatures closer to late-winter normals over the course of the week.

Prices in the Midwest fall slightly at the end of the report week as temperatures return to levels on par with the previous week. After reaching into the 90s last weekend, over 20ºF above normal, maximum daily temperatures in the Midwest dropped into the 60s yesterday, on par with the previous week but about 8ºF below normal. At the Chicago Citygate, the price decreased 1¢ from $2.78/MMBtu last Wednesday to $2.77/MMBtu yesterday, after reaching a weekly low of $2.67/MMBtu on Friday. The Natural Gas Intelligence Midwest Regional average similarly declined week over week, from $2.77 last Wednesday to $2.72/MMBtu yesterday, after dropping to a weekly low of $2.65/MMBtu on Friday. The Midwest Regional average price rose as high as $2.75/MMBtu on Tuesday, when overnight temperatures in some regions of the Midwest dropped below 30ºF.

California prices mixed, as storage facility maintenance in Southern California reaches completion. The price at PG&E Citygate in Northern California fell 11¢, down from $4.02/MMBtu last Wednesday to $3.91/MMBtu yesterday, reflecting consumption declines in supply regions; IHS Markit reported demand in the Rockies and the Pacific Northwest declined week over week, by 110 million cubic feet per day (MMcf/d) and 200 MMcf/d, respectively. Prices at Sumas, the main delivery point for natural gas imported from Canada into the Pacific Northwest, fell 5¢ from $2.81/MMBtu last Wednesday to $2.76/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, fell 8¢ from $2.88/MMBtu last Wednesday to $2.80/MMBtu yesterday. Prices at Sumas and Opal reached weekly lows on Friday, at $2.66/MMBtu and $2.69/MMBtu, respectively, when mean daily temperatures across the Northwest rose up to 14ºF above normal.

After falling 11¢ last week, the price at SoCal Citygate in Southern California increased 34¢ from $3.48/MMBtu last Wednesday to $3.82/MMBtu yesterday. Southern California Gas (SoCalGas) is no longer reporting significant reductions in storage capacity injections at the Honor Rancho storage facility, allowing the system to balance and clearing excess natural gas supply from the market, thereby alleviating the downward pressure on SoCal Citygate prices over the past three weeks.

Prices in the Northeast rise along with a return to heating demand as below-normal temperatures sweep across the region late in the report week. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 42¢ from $2.47/MMBtu last Wednesday to $2.89/MMBtu yesterday, after rising to $3.03/MMBtu on Monday. Temperatures in Boston averaged just 49ºF yesterday, or 6ºF below normal, and did not rise above 50ºF for the day, 13ºF below the normal daily high, resulting in elevated heating demand. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 8¢ from $2.36/MMBtu last Wednesday to $2.44/MMBtu yesterday, after falling to a low of $2.09/MMBtu on Friday, when temperatures in New York City averaged 63ºF, or 5ºF above normal, reducing space heating demand. Cooler weather near the end of the report week led to a rise in heating demand, as temperatures in New York dropped to an average of 55ºF, or 5ºF below normal.

Prices in the Appalachian Basin production region are mixed as pipeline maintenance results in market dislocation. The price at Tennessee Zone 4 Marcellus, in northeast Pennsylvania, decreased 41¢ from $1.91/MMBtu last Wednesday to $1.50/MMBtu yesterday, after falling to $0.95/MMBtu on Friday. Williams reports maintenance on its Leidy Line, which provides an outlet for northeast Pennsylvania production, resulting in reduced takeaway capacity and downward pressure on prices in the region. The price at Dominion South in southwest Pennsylvania, rose 9¢ from $2.24/MMBtu last Wednesday to a weekly high of $2.33/MMBtu yesterday.

Prices in the Permian production basin decline as production grows. The price at the Waha Hub in West Texas fell 7¢ per MMBtu, from $2.76/MMBtu last Wednesday to $2.69/MMBtu yesterday. The discount at Waha relative to the Henry Hub has grown from 17¢/MMBtu last week to 28¢/MMBtu, reflecting growing production, which IHS Markit estimates has risen on average by 0.5 billion cubic feet per day (Bcf/d) week over week. The growth in production has constrained capacity on takeaway pipelines, which is not expected to grow until the third quarter, when the Whistler Pipeline is scheduled to enter service.

U.S. supply of natural gas remains mostly flat. According to data from IHS Markit, the average total supply of natural gas fell slightly by 0.1% compared with the previous report week. Dry natural gas production remained mostly flat week over week at 91.6 Bcf/d, a 0.2% increase compared with the previous report week. Average net imports from Canada decreased by 5.6% from last week.

Warm weather increases cooling demand. Total U.S. consumption of natural gas rose by 0.4% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 4.1% week over week, as temperatures were warmer than normal for most of the country, increasing cooling demand. Industrial sector consumption decreased by 3.3% week over week. In the residential and commercial sectors, consumption declined slightly by 0.4%. Natural gas exports to Mexico decreased 0.5%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) exceeded 11 Bcf/d again this week, averaging 11.2 Bcf/d, or 0.13 Bcf/d lower than last week.

U.S. LNG exports increase week over week. Twenty two LNG vessels (seven from Sabine Pass, five from Corpus Christi, four each from Cameron and Freeport, and one each from Cove Point and Elba Island) with a combined LNG-carrying capacity of 84 Bcf departed the United States between April 29 and May 5, 2021, according to shipping data provided by Bloomberg Finance, L.P.

Storage:

The net injections into storage totaled 60 Bcf for the week ending April 30, compared with the five-year (2016–2020) average net injections of 81 Bcf and last year's net injections of 103 Bcf during the same week. Working natural gas stocks totaled 1,958 Bcf, which is 61 Bcf lower than the five-year average and 345 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 injections of 50 Bcf to 76 Bcf, with a median estimate of 62 Bcf.

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 ($/MMBtu)
Thu,
29-Apr
Fri,
30-Apr
Mon,
03-May
Tue,
04-May
Wed,
05-May
Henry Hub
2.85
2.88
2.93
3.01
2.97
New York
2.34
2.09
2.39
2.43
2.44
Chicago
2.72
2.67
2.78
2.79
2.77
Cal. Comp. Avg.*
3.19
3.16
3.21
3.23
3.25
Futures ($/MMBtu)
June contract
2.911
2.931
2.966
2.967
2.938
July contract
2.961
2.978
3.014
3.012
2.982
*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: (4/29/21 - 5/5/21)
Average daily values (Bcf/d):
this week
last week
last year
Marketed production
103.8
103.3
100.2
Dry production
91.6
91.4
89.4
Net Canada imports
4.5
4.8
3.1
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
96.1
96.2
92.5

Source: IHS Markit
Note: LNG pipeline deliveries represent natural gas sendout from LNG import terminals.

U.S. natural gas consumption - Gas Week: (4/29/21 - 5/5/21)
Average daily values (Bcf/d):
this week
last week
last year
U.S. consumption
67.1
66.9
58.4
    Power
27.3
26.2
24.9
    Industrial
21.9
22.6
20.3
    Residential/commercial
18.0
18.0
13.2
Mexico exports
5.9
6.0
4.4
Pipeline fuel use/losses
6.3
6.3
6.0
LNG pipeline receipts
11.2
11.3
7.6
Total demand
90.5
90.4
76.4

Source: IHS Markit
Note: LNG pipeline receipts represent pipeline deliveries to LNG export terminals.

Natural gas supply


Weekly natural gas rig count and average Henry Hub
Rigs
Tue, April 27, 2021
Change from
 
last week
last year
Oil rigs
342
-0.3%
5.2%
Natural gas rigs
96
2.1%
18.5%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, April 27, 2021
Change from
 
last week
last year
Vertical
19
-13.6%
72.7%
Horizontal
398
0.3%
6.4%
Directional
23
21.1%
0.0%
Source: Baker Hughes Co.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2021-04-30
2021-04-23
change
East
332
319
13
Midwest
442
427
15
Mountain
 124
 119
5
Pacific
224
217
7
South Central
836
816
20
Total
1,958
1,898
60
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report
Working gas in underground storage
Historical comparisons
Year ago
(4/30/20)
5-year average
(2016-2020)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
421
-21.1
346
-4.0
Midwest
527
-16.1
429
3.0
Mountain
110
12.7
117
6.0
Pacific
227
-1.3
219
2.3
South Central
1,020
-18.0
908
-7.9
Total
2,303
-15.0
2,019
-3.0
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Apr 29)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
98
-9
-54
0
0
0
Middle Atlantic
75
-15
-60
1
1
1
E N Central
83
-11
-29
2
1
2
W N Central
86
2
17
3
0
3
South Atlantic
43
3
-18
32
10
9
E S Central
38
2
-13
14
6
12
W S Central
11
-2
2
42
12
-3
Mountain
91
-3
26
5
-6
-15
Pacific
65
11
51
1
-4
-11
United States
67
-3
-8
13
2
0
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-day mean ending Apr 29, 2021

Mean Temperature (F) 7-Day Mean ending Apr 29, 2021

Source: National Oceanic and Atmospheric Administration

Deviation between average and normal (°F)

7-day mean ending Apr 29, 2021

Mean Temperature Anomaly (F) 7-Day Mean ending Apr 29, 2021

Source: National Oceanic and Atmospheric Administration