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As of July 6, 2022, we have restored most of our data publications. A complete list of releases for the week is available. We will publish U.S. diesel prices on Thursday, July 7, at 4:00 p.m. We will continue to provide updates regarding the status of diesel prices and other data products.

Natural Gas

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Natural Gas Weekly Update

for week ending June 8, 2022   |  Release date:  June 9, 2022   |  Next release:  June 16, 2022   |   Previous weeks

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

In the News:

EIA forecasts that Gulf of Mexico natural gas production will decline in 2023 despite new projects

In our June 2022 Short-Term Energy Outlook (STEO), we forecast that new projects coming online in 2022 in the U.S. Federal Offshore Gulf of Mexico (GOM) will contribute 6% of natural gas and 15% of crude oil production to GOM totals by the end of 2023. However, the new projects will sustain GOM oil production at relatively flat levels, similar to 2021 year-end activity. We expect natural gas production to continue declining throughout the forecast period.

Our STEO assumptions include the development of eight fields/leases by six projects in the GOM that either began producing both oil and natural gas in 2022 or are expected to produce by year’s end, and are based, in part, on data from Rystad Energy. A ninth field scheduled to start in 2022 will likely produce only crude oil.

GOM natural gas production will average 2.1 billion cubic feet per day (Bcf/d) in 2023, down from 2.2 Bcf/d in 2022. GOM crude oil production will average 1.8 million barrels per day (b/d) in 2023, about the same as in 2022. Currently, our STEO forecast does not include new GOM projects scheduled to begin producing in 2023. However, our 2023 forecast may change if projects expected to start in 2022 delay start-up dates or if projects expected to start in 2024 begin earlier.

Today, most of the natural gas produced in GOM comes from associated-dissolved natural gas production in oil fields instead of natural gas fields. In 2020, gross withdrawals of natural gas in GOM that came from natural gas wells accounted for less than 30% of total GOM natural gas production, compared with 80% in 2003. Since the late 1990s, new development in GOM has primarily targeted oil-bearing reservoirs.

Offshore producers have become increasingly efficient as onshore production from tight-oil reservoirs has become more competitive. The result has been a focused effort to simplify and standardize floating production systems and to collaborate with various partners, including overseas construction service companies, to reduce engineering, procurement, and construction costs. Multiple new projects coming online in 2022 demonstrate this trend. BP’s Argos, Murphy’s King’s Quay, and Shell’s Vito projects each have a peak production capacity of 100,000 barrels of oil equivalent per day or more, and all are floating production systems that involve international collaboration. The production facilities for these projects were constructed in South Korea or Singapore before being shipped to the United States for inspection and final preparation for installation in GOM.

Overview:

(For the week ending Wednesday, June 8, 2022)

  • Spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, June 1 to Wednesday, June 8). The Henry Hub spot price rose from $8.42 per million British thermal units (MMBtu) last Wednesday to $9.46/MMBtu yesterday, the highest daily price since a winter storm contributed to near record-high spot prices in February 2021.
  • International spot prices: International natural gas spot prices were mixed this report week. Bloomberg Finance, L.P., reports that the average weekly swap prices for liquefied natural gas (LNG) cargoes in East Asia were flat week over week at $23.77/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead price fell $2.02/MMBtu to a weekly average of $24.49/MMBtu. In the same week last year (week ending June 9, 2021), the prices in East Asia and at TTF were $10.65/MMBtu and $9.58/MMBtu, respectively.
  • Futures: The price of the July 2022 NYMEX contract was unchanged Wednesday to Wednesday at $8.699/MMBtu. The price of the 12-month strip averaging July 2022 through June 2023 futures contracts increased 20.9 cents to $7.897/MMBtu. On Monday, the front month futures contract closed at $9.322/MMBtu, its highest closing price since August 2008. News on Wednesday of an explosion at Freeport LNG, one of the largest LNG export facilities in the United States, contributed to a decline of 59 cents in the front month closing price between Tuesday and Wednesday.
  • Storage: The net injections to working gas totaled 97 billion cubic feet (Bcf) for the week ending June 3. Working natural gas stocks totaled 1,999 Bcf, which is 17% lower than the year-ago level and 15% 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 18 cents/MMBtu, averaging $13.00/MMBtu for the week ending June 8. Weekly average ethane prices rose 4%, following the 5% increase in natural gas prices at the Houston Ship Channel. The ethane premium to natural gas widened by 1%. The price of ethylene rose 2%, which narrowed the ethylene to ethane spread by 4%. The Brent crude oil price rose 5%, pulling up the price of natural gasoline, which rose 2%. Normal butane and isobutane prices fell 2%. The propane price remained relatively unchanged, widening the propane discount to crude oil by 13%.
  • Rigs: According to Baker Hughes, for the week ending Tuesday, May 31, the natural gas rig count was unchanged from a week ago at 151 rigs. The Haynesville dropped one rig and one rig was added in an unspecified producing region for a net gain of zero. The number of oil-directed rigs also held steady this week at 574 rigs. The Cana Woodford and the DJ-Niobrara each dropped one rig, and two rigs were added in unspecified producing regions for a zero net gain. The total rig count stands at 727, which is 271 rigs more than the same week last year.

more summary data

Prices/Supply/Demand:

Prices along the Gulf Coast rise as higher temperatures result in increased demand for air conditioning. This report week (Wednesday, June 1 to Wednesday, June 8), the Henry Hub spot price rose $1.04 from $8.42 per million British thermal units (MMBtu) last Wednesday to $9.46/MMBtu yesterday. Prices across the South rose this week, as higher temperatures led to increased demand for air conditioning. Natural gas consumption in the electric power sector along the Texas Gulf Coast (South Texas sub-region) and across the Southeast region rose by a combined 1.0 billion cubic feet per day (Bcf/d) (7%) this report week. Temperatures in the Houston Area averaged 84°F this report week, 2°F higher than normal, leading to 135 cooling degree days (CDD), which is 17 CDDs more than normal for this time of year. Deliveries to LNG export terminals in South Texas fell by 0.4 Bcf/d (9%) to 3.9 Bcf/d, while deliveries to LNG export terminals in South Louisiana rose slightly to 7.4 Bcf/d, according to data from PointLogic. Freeport LNG, the operator of one of the largest U.S. LNG export terminals in South Texas, suffered an unplanned outage yesterday and is expected to remain out of service for at least three weeks, according to a statement from Freeport LNG. The terminal had been receiving approximately 2.0 Bcf/d of feed gas in recent weeks.

Prices across the West rise as temperatures increase in California and the Desert Southwest. The price at PG&E Citygate in Northern California rose 70 cents, up from $9.61/MMBtu last Wednesday to $10.31/MMBtu yesterday, as prices at major origin points for natural gas into the PG&E service territory also rose. The price at Opal in southwest Wyoming, the origin point of the Ruby Pipeline that delivers natural gas into the Malin, Oregon hub and the main northern delivery point into the PG&E service region, rose 66 cents from $8.21/MMBtu last Wednesday to $8.87/MMBtu yesterday.

The price at SoCal Citygate in Southern California increased $1.52 from $9.00/MMBtu last Wednesday to $10.52/MMBtu yesterday, as temperatures across much of California increased to above-normal levels, particularly in Southern California. Temperatures in the Riverside Area, inland from Los Angeles, averaged 74°F this report week, which is 5°F higher than last report week and 3°F higher than normal. The National Oceanic and Atmospheric Administration (NOAA) forecasts temperatures across the West, particularly in California and in the Desert Southwest will remain above normal through the weekend. Natural gas consumption in the electric power sector in California increased by 0.2 Bcf/d (21%), according to data from PointLogic. Natural gas consumption also rose by 0.2 Bcf/d (13%) in the electric power sector in the Desert Southwest, through which one of the main pipelines into the SoCalGas service area passes. As a result, prices on the El Paso South Mainline/North Baja rose by $1.85, from $8.69 last Wednesday to $10.53/MMBtu yesterday, according to Natural Gas Intelligence.

Prices are mixed in the Northeast on differing fundamentals. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 29 cents from $8.84/MMBtu last Wednesday to $8.55/MMBtu yesterday. The Algonquin Citygate moved in the opposite direction of other major pricing hubs this week, and the price differential between the Algonquin Citygate and the Henry Hub flipped from trading 42 cents above Henry Hub on June 1 to trading 91 cents below Henry Hub yesterday. Natural gas consumption in New England was flat this week compared with last week at 1.7 Bcf/d. On May 24, the Everett LNG facility received its seventh LNG cargo since the beginning of the year, according to shipping data provided by Bloomberg Finance, L.P. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 59 cents from $7.85/MMBtu last Wednesday to $8.44/MMBtu yesterday. Natural gas flows into the New York and New Jersey area decreased by 85 million cubic feet per day (1%) this week, according to data from PointLogic. A notice from Kinder Morgan, the operator of the Tennessee Gas Pipeline, reported maintenance on Tuesday and Thursday this week at compressor station 321, which is north of Scranton, Pennsylvania, resulting in a 1.1 Bcf/d capacity reduction on the line flowing west to east to 0.9 Bcf/d.

Prices in the Appalachian production region rise as demand from the electric power sector increases. The Tennessee Zone 4 Marcellus spot price increased 64 cents from $7.50/MMBtu last Wednesday to $8.14/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 62 cents from $7.62/MMBtu last Wednesday to $8.24/MMBtu yesterday. Natural gas demand increased by 0.5 Bcf/d (2%) week over week, according to data from PointLogic. Consumption in the electric power sector increased by 0.3 Bcf/d (8%), and natural gas flows to the Southern Corridor rose by 0.4 Bcf/d (6%) in response to higher natural gas consumption for power generation because of increased air-conditioning demand in the Southeast.

Production in the Permian Basin falls and prices rise. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose $1.16 this report week, from $7.56/MMBtu last Wednesday to $8.72/MMBtu yesterday. The Waha Hub traded 74 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 86 cents below the Henry Hub price. Production in the New Mexico side of the Permian Basin fell by 0.2 Bcf/d (4%) from a week ago, according to data from PointLogic. Although the Permian Basin is not a large consumer of natural gas, in-basin consumption increased by 0.1 Bcf/d (38%) week over week to an average 0.4 Bcf/d, driven primarily by consumption in the electric power sector, which rose 63% week over week in response to unseasonably high temperatures. NOAA reports temperatures in the Midland-Odessa Area in Texas reached 103°F on Monday and Tuesday, 9°F and 8°F above normal daily highs, respectively.

U.S. natural gas supply is unchanged week over week. Overall U.S. natural gas supply remains unchanged this report week at 100.8 Bcf/d, according to data from PointLogic. Dry natural gas production fell by 0.5% (0.5 Bcf/d), while net imports from Canada increased by 9.9% (0.5 Bcf/d) from the previous report week.

U.S. natural gas demand increases as temperatures rise across the country. Total U.S. consumption of natural gas rose by 1.8% (1.1 Bcf/d) compared with the previous report week, according to data from PointLogic. Temperatures generally rose but remained close to normal across much of the United States, with some isolated pockets of higher- and lower-than-normal temperatures. The power generation sector accounted for the largest change in consumption week over week, rising by 6.9% (2.1 Bcf/d), as air-conditioning demand increased. Meanwhile, in the residential and commercial sectors, consumption declined by 10.5% (1.0 Bcf/d), as demand for space heating declined. Industrial sector consumption was essentially unchanged this report week. Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) fell slightly this report week, averaging 12.5 Bcf/d, or 0.3 Bcf/d lower than last week. Natural gas exports to Mexico decreased by 1.5% (0.1 Bcf/d).

U.S. LNG exports decrease by one vessel this week from last week. Twenty-two LNG vessels (seven from Sabine Pass, five from Freeport, four from Corpus Christi, three from Cameron, two from Calcasieu Pass, and one from Cove Point) with a combined LNG-carrying capacity of 82 Bcf departed the United States between June 2 and June 8, according to shipping data provided by Bloomberg Finance, L.P.

Storage:

The net injections into storage totaled 97 Bcf for the week ending June 3, compared with the five-year (2017–2021) average net injections of 100 Bcf and last year's net injections of 98 Bcf during the same week. Working natural gas stocks totaled 1,999 Bcf, which is 340 Bcf lower than the five-year average and 398 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 85 Bcf to 105 Bcf, with a median estimate of 99 Bcf.

The average rate of injections into storage is 9% 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 8.7 Bcf/d for the remainder of the refill season, the total inventory would be 3,305 Bcf on October 31, which is 340 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:

Monthly U.S. Federal Offshore Gulf of Mexico marketed natural gas production (Jan 2019–Dec 2023)
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook
Monthly U.S. Federal Offshore Gulf of Mexico crude oil production (Jan 2019–Dec 2023)
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook


Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
02-Jun
Fri,
03-Jun
Mon,
06-Jun
Tue,
07-Jun
Wed,
08-Jun
Henry Hub
8.86
8.36
9.00
9.26
9.46
New York
7.49
7.20
7.97
8.23
8.44
Chicago
8.51
7.98
8.68
8.89
9.08
Cal. Comp. Avg.*
9.15
8.44
9.16
9.51
9.74
Futures ($/MMBtu)
July contract
8.485
8.523
9.322
9.293
8.699
August contract
8.474
8.510
9.306
9.278
8.679
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: (6/2/22 - 6/8/22)
Average daily values (billion cubic feet)
this week
last week
last year
Marketed production
107.5
108.1
105.2
Dry production
95.5
96.0
92.9
Net Canada imports
5.3
4.8
4.2
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
100.8
100.8
97.1

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: (6/2/22 - 6/8/22)
Average daily values (billion cubic feet)
this week
last week
last year
U.S. consumption
62.5
61.4
63.8
    Power
32.4
30.3
33.3
    Industrial
21.4
21.4
21.1
    Residential/commercial
8.7
9.7
9.4
Mexico exports
5.6
5.7
6.3
Pipeline fuel use/losses
6.3
6.3
6.2
LNG pipeline receipts
12.5
12.8
10.0
Total demand
86.8
86.1
86.4

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, May 31, 2022
Change from
 
last week
last year
Oil rigs
574
0.0%
59.9%
Natural gas rigs
151
0.0%
55.7%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, May 31, 2022
Change from
 
last week
last year
Vertical
25
0.0%
56.3%
Horizontal
666
0.0%
60.5%
Directional
36
0.0%
44.0%
Data source: Baker Hughes Company


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2022-06-03
2022-05-27
change
East
387
357
30
Midwest
445
420
25
Mountain
 118
 113
5
Pacific
206
195
11
South Central
843
817
26
Total
1,999
1,902
97
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
(6/3/21)
5-year average
(2017-2021)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
440
-12.0
448
-13.6
Midwest
543
-18.0
523
-14.9
Mountain
159
-25.8
141
-16.3
Pacific
275
-25.1
255
-19.2
South Central
980
-14.0
972
-13.3
Total
2,397
-16.6
2,339
-14.5
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Jun 02)
 
HDDs
CDDs
Region
Current total
Deviation from normal
Deviation from last year
Current total
Deviation from normal
Deviation from last year
New England
14
-20
-51
14
10
10
Middle Atlantic
3
-22
-49
32
20
28
E N Central
12
-17
-48
34
14
33
W N Central
18
-8
-36
29
2
22
South Atlantic
0
-8
-17
76
20
21
E S Central
3
-4
-14
58
10
21
W S Central
1
0
-5
99
21
37
Mountain
45
6
15
31
-3
-7
Pacific
22
-4
14
4
-10
-16
United States
13
-10
-23
44
10
18
Data source: National Oceanic and Atmospheric Administration
Note: HDDs=heating degree days; CDDs=cooling degree days

   Average temperature (°F)


    7-day mean ending Jun 02, 2022

Mean Temperature (F) 7-Day Mean ending Jun 02, 2022

        Data source: National Oceanic and Atmospheric Administration

  Deviation between average and normal temperature (°F)


   7-day mean ending Jun 02, 2022

Mean Temperature Anomaly (F) 7-Day Mean ending Jun 02, 2022

        Data source: National Oceanic and Atmospheric Administration