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Natural Gas Weekly Update

for week ending June 22, 2022   |  Release date:  June 23, 2022   |  Next release:  June 30, 2022   |   Previous weeks

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

In the News:

First-year productivity of Haynesville and Marcellus wells more than doubled between 2014 and 2020

This article is the third in a series on natural gas well productivity changes over time in the Haynesville and the Marcellus shale formations.

Wells in the Haynesville and Marcellus shale gas plays, which combined produced 39% of all U.S. dry natural gas in 2021, more than doubled their first-year cumulative production per well from 2014 to 2020. The average Haynesville well increased its first-year natural gas cumulative production 165% over this time, and the average Marcellus well increased production by 189% across the same amount of time.

Despite similar volumetric increases in the first year of cumulative production, the profile of the volume of natural gas produced per foot of lateral length is quite different when comparing a Marcellus well with a Haynesville well. By design, a horizontal well produces from an interval of natural gas-bearing rock as wide as the lateral section of the wellbore is long. As a result of increased lateral length within a given wellbore, the extent of natural gas-bearing rock accessed by the wellbore increases in direct proportion to this additional lateral length.

Wells in the Marcellus formation have shown a consistent pattern of improving productivity per foot of lateral length drilled, whereas wells in the Haynesville formation, while continuing to improve overall, exhibited a diminishing productivity per foot of lateral length drilled from 2014 to 2020. The Haynesville well lateral length growth has decreased consistently since 2016, following its 8.1% increase between 2014 and 2016. From 2018 to 2020, it dropped to only 3.2%. The Marcellus well lateral length increased 5.8% from 2014 to 2016, and then it continued to increase by 10.6% from 2016 to 2018 and 9.7% from 2018 to 2020.

First-month well productivity (when normalized for lateral length) is another measure of well performance over time. The rate of biannual normalized improvement in first-month natural gas production in the Haynesville formation wells has fallen steadily from 53.5% between 2014 and 2016 to 4.7% between 2018 and 2020. The normalized improvement for the average Marcellus formation well remained relatively consistent between 27.7% and 31.2% from 2014 to 2020.

The ability to increase normalized productivity measures usually reaches a limit at some point, as the balance between the cost of drilling the lateral section of the well and accompanying completion is optimized by companies for a particular formation across the entire play. The Haynesville formation appears closer to that optimized balance than the Marcellus formation, which continued to show productivity gains through 2020.

Overview:

(For the week ending Wednesday, June 22, 2022)

  • Spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, June 15 to Wednesday, June 22). The Henry Hub spot price fell from $7.72 per million British thermal units (MMBtu) last Wednesday to $6.59/MMBtu yesterday.
  • International spot prices: International natural gas spot prices increased this report week. Bloomberg Finance, L.P., reports that the weekly average swap prices for liquefied natural gas (LNG) cargoes in East Asia increased $9.20 to a weekly average of $32.29/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead price rose $9.38 to a weekly average of $37.07/MMBtu. In the same week last year (week ending June 23, 2021), the prices in East Asia and at TTF were $11.88/MMBtu and $10.52/MMBtu, respectively.
  • Futures: The price of the July 2022 NYMEX contract decreased 56.2 cents, from $7.420/MMBtu last Wednesday to $6.858/MMBtu yesterday. The price of the 12-month strip averaging July 2022 through June 2023 futures contracts declined 62.9 cents to $6.325/MMBtu.
  • Storage: The net injections to working gas totaled 74 billion cubic feet (Bcf) for the week ending June 17. Working natural gas stocks totaled 2,169 Bcf, which is 12% lower than the year-ago level and 13% lower than the five-year (2017–2021) average for this week.
  • NGPLs: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 44 cents/MMBtu, averaging $12.21/MMBtu for the week ending June 22. Weekly average natural gas prices at the Houston Ship Channel fell 14%, pulling down the price of ethane, which fell 8%. The ethane premium to natural gas widened by 13%. Despite the price of ethylene falling by 5%, the larger decrease in the ethane price led to a widening of the ethylene to ethane spread by 6%. Natural gasoline prices fell 5%, following the Brent crude oil price decline of 7%. The normal butane price fell 1%, and isobutane rose 2%. The propane price remained relatively unchanged, narrowing the propane discount to crude oil by 19%.
  • Rigs: According to Baker Hughes, for the week ending Tuesday, June 14, the natural gas rig count increased by 3 rigs from a week ago to 154 rigs. The Haynesville added one rig, and two rigs were added in unspecified producing regions. The number of oil-directed rigs increased by 4 rigs to 584 rigs. The Cana Woodford added two rigs, the Ardmore Woodford, the Eagle Ford, and an unspecified producing region each added one rig, and one rig was dropped in the Granite Wash. The total rig count now stands at 740, the highest level since March 20, 2020, and 270 rigs more than the same week last year.

more summary data

Prices/Supply/Demand:

Prices along the Gulf Coast fall, even as temperatures remain above normal in the region. This report week (Wednesday, June 15 to Wednesday, June 22), the Henry Hub spot price fell $1.13 from $7.72/MMBtu last Wednesday to $6.59/MMBtu yesterday. Prices along the Gulf Coast declined this week, even as temperatures remained above normal. Weekly average natural gas consumption in the electric power sector along the Gulf Coast (South Texas and South Louisiana subregions) and across the Southeast region rose by a combined 0.5 billion cubic feet per day (Bcf/d) (3%) this report week, according to data from PointLogic. Temperatures in the Houston Area averaged 88°F this week, 4°F higher than normal. Natural gas deliveries to LNG export terminals in South Texas were unchanged at 2.3 Bcf/d, while deliveries to LNG export terminals in South Louisiana increased slightly by 0.1 Bcf/d (1%) to 7.2 Bcf/d. Following a fire that caused the full shutdown of plant operations at its 2.1 Bcf/d peak-capacity LNG liquefaction plant in South Texas, Freeport LNG issued a press release last Tuesday. The company stated that it does not expect a return to full plant operations until late 2022, although “a resumption of partial operations is targeted to be achieved in approximately 90 days.”

Prices in the Midwest fall with the national average as temperatures fluctuate. At the Chicago Citygate, the price decreased 86 cents from $7.42/MMBtu last Wednesday to $6.56/MMBtu yesterday. Natural gas consumption in the residential and commercial sectors in the Midwest increased by 0.2 Bcf/d (12%), while natural gas consumption in the electric power sector increased by 0.1 Bcf/d (2%) this report week, according to data from PointLogic. Temperatures in the Chicago Area averaged 76°F this report week, 5°F higher than normal. On Saturday, temperatures averaged 64°F, which is 8°F lower than normal, and by Tuesday temperatures averaged 86°F, 14°F higher than normal.

Prices across most of the West decline as temperatures return to near normal, while prices in Southern California remain at elevated levels. The price at PG&E Citygate in Northern California fell 58 cents, down from $8.57/MMBtu last Wednesday to $7.99/MMBtu yesterday, as prices at major origin points for natural gas into the PG&E service territory also fell. The price at Opal in southwest Wyoming (the origin point of the Ruby Pipeline that delivers natural gas into Malin, Oregon, and the main northern delivery point into the PG&E service region) fell 66 cents from $7.12/MMBtu last Wednesday to $6.46/MMBtu yesterday.

The price at SoCal Citygate in Southern California increased 14 cents from $7.59/MMBtu last Wednesday to $7.73/MMBtu yesterday. The price at SoCal Citygate rose in response to rapidly rising temperatures and a resulting increase in natural gas consumption for power generation. A declaration of force majeure on the El Paso Pipeline also contributed to the price increase. Temperatures in the Riverside Area, inland from Los Angeles, averaged 76°F this report week, which is 3°F higher than normal. After declining to 71°F on Saturday, 3°F below normal, daily average temperatures in the Riverside Area reached 83°F on Wednesday, 8°F higher than normal. Natural gas consumption in the electric power sector decreased week-over-week by 0.2 Bcf/d (12%) in California and by 0.2 Bcf/d (9%) in the Desert Southwest, according to data from PointLogic. On Wednesday, June 22, Kinder Morgan, operator of the El Paso Pipeline that ships natural gas across the Southwest into California from the Permian Basin announced the force majeure on their El Paso C compressor in eastern New Mexico. Effective June 23, capacity to ship natural gas westward decreased by approximately 0.1 Bcf/d.

Prices in the Northeast decrease with the national average. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.53 from $7.45/MMBtu last Wednesday to $5.92/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased $1.43 from $7.33/MMBtu last Wednesday to $5.90/MMBtu yesterday. Natural gas consumption in the Northeast decreased 0.1 Bcf/d (1%) week over week, according to data from PointLogic. Temperatures in the Boston Area averaged 65°F, which was 5°F below normal for the week. Below-normal temperatures in New England resulted in a slight increase in consumption in the residential and commercial sectors, which was offset by a week-over-week decrease in consumption in the electric power sector of 0.1 Bcf/d (12%). The New York and New Jersey area experienced a similar trend by sector, and overall consumption decreased by 0.3 Bcf/d (8%) week over week.

Prices in the Appalachia production region fall along with other major price hubs. The Tennessee Zone 4 Marcellus spot price decreased $1.29 from $6.99/MMBtu last Wednesday to $5.70/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell $1.21 from $6.98/MMBtu last Wednesday to $5.77/MMBtu yesterday. Natural gas consumption within the Appalachia production region rose by 0.3 Bcf/d (4%) week over week, according to data from PointLogic. Net natural gas flows out of the region decreased by 0.6 Bcf/d (3%), which offset higher in-region consumption, and led the decline in overall natural gas demand of 0.4 Bcf/d (1%) from a week ago.

Prices in the Permian production region fall by less than the Henry Hub price, narrowing the discount to Henry Hub. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 62 cents this report week, from $6.70/MMBtu last Wednesday to $6.08/MMBtu yesterday. The Waha Hub traded 51 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded $1.02 below the Henry Hub price and with last Friday when it traded $1.15 below. Prices in the Permian production region were volatile during the week as markets continued to adjust to a decline of approximately 2 Bcf/d in demand along the Gulf Coast because of the Freeport LNG outage.

U.S. natural gas supply decreases week over week as net imports from Canada fall. Overall U.S. natural gas supply decreased slightly by 0.4% (0.4 Bcf/d) week over week to 101.2 Bcf/d, according to data from PointLogic. Dry natural gas production remained unchanged at 95.5 Bcf/d, and net imports from Canada fell by 7.1% (0.4 Bcf/d).

U.S. natural gas demand increases as high-consumption regions along the East and West coasts cool to below normal, even as temperatures remain above normal across much of the central United States. Total U.S. consumption of natural gas rose slightly by 0.5% (0.3 Bcf/d) week over week, according to data from PointLogic. Weekly average temperatures were higher than normal across the southern United States and Midcontinent, while temperatures along the Pacific and Atlantic coasts were lower than normal this report week. In the residential and commercial sectors, natural gas consumption increased by 3.7% (0.3 Bcf/d), while in the electric power sector, consumption rose by 0.3% (0.1 Bcf/d) week over week. Industrial sector consumption decreased by 0.4% (0.1 Bcf/d), and exports to Mexico decreased 4.6% (0.3 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 10.7 Bcf/d, or 0.1 Bcf/d higher than last week.

U.S. LNG exports decrease by three vessels this week from last week. Eighteen LNG vessels (eight from Sabine Pass, four from Corpus Christi, three from Cameron, and one each from Calcasieu Pass, Cove Point, and Elba Island) with a combined LNG-carrying capacity of 68 Bcf departed the United States between June 16 and June 22, according to shipping data provided by Bloomberg Finance, L.P. The Freeport LNG facility on Quintana Island, Texas, south of Houston remains offline following a fire on June 8.

Storage:

The net injections into storage totaled 74 Bcf for the week ending June 17, compared with the five-year (2017–2021) average net injections of 82 Bcf and last year's net injections of 49 Bcf during the same week. Working natural gas stocks totaled 2,169 Bcf, which is 331 Bcf lower than the five-year average and 305 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 56 Bcf to 71 Bcf, with a median estimate of 63 Bcf.

The average rate of injections into storage is 6% 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 8.4 Bcf/d for the remainder of the refill season, the total inventory would be 3,314 Bcf on October 31, which is 331 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.

See also:

Haynesville and Marcellus vintage natural gas well production by select year, first 12 months
Data source: Enverus DrillingInfo
Haynesville and Marcellus average lateral length change between vintage years
Data source: Enverus DrillingInfo
Haynesville and Marcellus normalized initial production rate improvement between vintage years
Data source: Enverus DrillingInfo


Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
16-Jun
Fri,
17-Jun
Mon,
20-Jun
Tue,
21-Jun
Wed,
22-Jun
Henry Hub 7.89 7.34 Holiday 6.62 6.59
New York 7.50 6.30 Holiday 5.78 5.90
Chicago 7.52 6.94 Holiday 6.50 6.56
Cal. Comp. Avg.* 7.79 7.01 Holiday 6.81 7.22
Futures ($/MMBtu)
July Contract 7.464 6.944 Holiday 6.808 6.858
August Contract 7.438 6.906 Holiday 6.783 6.872
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: (6/16/22 - 6/22/22)
Average daily values (billion cubic feet)
this week
last week
last year
Marketed production
107.6
107.6
104.8
Dry production
95.5
95.5
92.7
Net Canada imports
5.6
6.1
4.7
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
101.2
101.6
97.5

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: (6/16/22 - 6/22/22)
Average daily values (billion cubic feet)
this week
last week
last year
U.S. consumption
68.2
67.8
66.3
    Power
38.3
38.2
36.4
    Industrial
21.0
21.1
21.1
    Residential/commercial
8.9
8.6
8.8
Mexico exports
5.8
6.1
6.9
Pipeline fuel use/losses
6.5
6.5
6.3
LNG pipeline receipts
10.7
10.7
9.9
Total demand
91.2
91.1
89.4

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, June 14, 2022
Change from
 
last week
last year
Oil rigs
584
0.7%
56.6%
Natural gas rigs
154
2.0%
58.8%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, June 14, 2022
Change from
 
last week
last year
Vertical
27
0.0%
35.0%
Horizontal
674
0.9%
58.6%
Directional
39
2.6%
56.0%
Data source: Baker Hughes Company


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2022-06-17
2022-06-10
change
East
430
407
23
Midwest
506
482
24
Mountain
 128
 122
6
Pacific
231
221
10
South Central
875
863
12
Total
2,169
2,095
74
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
(6/17/21)
5-year average
(2017-2021)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
484
-11.2
501
-14.2
Midwest
591
-14.4
577
-12.3
Mountain
168
-23.8
153
-16.3
Pacific
239
-3.3
260
-11.2
South Central
992
-11.8
1,009
-13.3
Total
2,474
-12.3
2,500
-13.2
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Jun 16)
 
HDDs
CDDs
Region
Current total
Deviation from normal
Deviation from last year
Current total
Deviation from normal
Deviation from last year
New England
7
-9
-8
11
0
3
Middle Atlantic
3
-6
-1
27
3
7
E N Central
7
-6
3
59
27
3
W N Central
2
-10
1
76
34
-1
South Atlantic
0
-2
0
94
22
10
E S Central
1
0
1
97
30
9
W S Central
0
0
0
139
40
14
Mountain
12
-12
7
70
19
-8
Pacific
9
-8
-3
32
11
2
United States
5
-6
0
68
21
5
Data source: National Oceanic and Atmospheric Administration
Note: HDDs=heating degree days; CDDs=cooling degree days

   Average temperature (°F)


    7-day mean ending Jun 16, 2022

Mean Temperature (F) 7-Day Mean ending Jun 16, 2022

        Data source: National Oceanic and Atmospheric Administration

  Deviation between average and normal temperature (°F)


   7-day mean ending Jun 16, 2022

Mean Temperature Anomaly (F) 7-Day Mean ending Jun 16, 2022

        Data source: National Oceanic and Atmospheric Administration