In the News:
U.S. LNG imports reach historic lows in first half of 2022
In the first six months of 2022, U.S. liquefied natural gas (LNG) imports reached their lowest level in at least 15 years, averaging 77 million cubic feet per day (MMcf/d), compared with the five-year (2017–2021) average for the same period of 174 MMcf/d. LNG imports are usually at their highest level in the winter months of October through March. This past winter, LNG imports averaged 93 MMcf/d, which is significantly lower than in the winter of 2006–2007, when LNG imports averaged 1.8 billion cubic feet per day (Bcf/d).
As a share of U.S. total natural gas imports, LNG imports accounted for less than 1% in 2021, down from almost 17% in 2007. LNG imports peaked in April 2007 at 3.3 Bcf/d, and they accounted for almost 26% of total natural gas imports. Over the past five years, LNG imports were at their highest level in January 2018 averaging 0.5 Bcf/d, or almost 6% of total natural gas imports that month.
Before 2010, the United States was expanding its LNG import infrastructure. Eight LNG import terminals were built between 2005 and 2011, increasing the number of U.S. terminals to 12. Domestic dry natural gas production began to grow rapidly around the same time and eventually many of those LNG import terminals were reconfigured into LNG export terminals.
U.S. dry natural gas production grew by nearly 80% from 2007 to 2021, displacing LNG imports, which declined rapidly during this period. Natural gas production has increased primarily in three production regions—Appalachia, Permian, and Haynesville. Production from the Appalachian Basin, which includes the Marcellus and Utica shale formations in the Northeast, accounted for 31% of total U.S. natural gas production in 2021.
With the growth in natural gas production, several pipeline projects were completed, improving the delivery of natural gas supplies from producing regions to consumption centers across most of the country. However, even after the completion of some projects, such as the Algonquin Incremental Market (AIM) project, supplies by pipeline into the New England market can be constrained during periods of peak demand. As a result, New England continues to rely on LNG imports, particularly during the winter when demand for natural gas is high. On peak demand days, imported LNG can contribute up to 35% of New England’s natural gas supply.
LNG imports can be a key marginal source of supply during times of high demand and help moderate natural gas prices. Almost all LNG imported into the United States today is delivered into the New England market at the import terminals in the Boston, Massachusetts, area—Constellation Energy’s Everett LNG Facility in Boston Harbor and Excelerate Energy’s Northeast Gateway in Massachusetts Bay. From November 2021 through March 2022, nine vessels carrying LNG from Trinidad and Tobago delivered 16.8 billion cubic feet of LNG to the two terminals.
Market Highlights:
(For the week ending Wednesday, September 21, 2022)Prices
- Henry Hub spot price: The Henry Hub spot price fell 70 cents from $8.69 per million British thermal units (MMBtu) last Wednesday to $7.99/MMBtu yesterday.
- Henry Hub futures prices: The price of the October 2022 NYMEX contract decreased $1.335, from $9.114/MMBtu last Wednesday to $7.779/MMBtu yesterday. The price of the 12-month strip averaging October 2022 through September 2023 futures contracts declined 97.6 cents to $6.448/MMBtu.
- Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, September 14, to Wednesday, September 21). Price decreases at major pricing hubs ranged between $0.70 at Henry Hub to $2.18 at SoCal Citygate.
In Southern California, the price at SoCal Citygate decreased $2.18 from $9.52/MMBtu last Wednesday to $7.34/MMBtu yesterday. Temperatures have continued to decline along the West Coast and across the Desert Southwest, following a heat wave that affected much of the region in early September. In the Riverside Area, inland from Los Angeles, temperatures averaged a little more than 73°F this week, leading to 59 cooling degree days (CDD), which is 51 fewer CDDs than last week and 132 fewer than two weeks ago. In the Phoenix Area, temperatures averaged 88°F, almost 1°F below normal. Natural gas consumption in the electric power sector in California declined 44%, or 1.1 billion cubic feet per day (Bcf/d), this report week, and in the Desert Southwest, it declined 15%, or 0.3 Bcf/d, according to data from PointLogic.
Further north, the price at PG&E Citygate in Northern California declined $1.54, from $9.83/MMBtu last Wednesday to $8.29/MMBtu yesterday. The price at Sumas on the Canada-Washington border fell $1.21, from $8.07/MMBtu last Wednesday to $6.86/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, fell $1.11 from $8.20/MMBtu last Wednesday to $7.09/MMBtu yesterday. In the Sacramento Area, temperatures averaged 68°F, which is 4°F below normal, leading to 24 CDDs this report week, compared with 99 CDDs last report week. In the Seattle City Area in the state of Washington, temperatures averaged 63°F, leading to 0 CDDs and 11 heating degree days (HDD), compared with 19 CDDs and 3 HDDs last report week. Natural gas consumption in all sectors declined by 6%, or 0.1 Bcf/d, in the Pacific Northwest this report week, according to data from PointLogic.
- The price at the Waha Hub in West Texas fell $2.16 this report week, from $7.25/MMBtu last Wednesday to $5.09/MMBtu yesterday. The Waha Hub has been trading at a growing discount to Henry Hub in recent months and yesterday traded $2.91 below the Henry Hub price, the largest discount to Henry Hub since July. The widening difference between the Waha Hub price and the Henry Hub price reflects reduced demand for natural gas across the Desert Southwest and Southern California, as well as reduced pipeline exports to Mexico, the primary markets the hub serves. It also reflects regional pipeline constraints on natural gas flowing to other markets. Planned pipeline projects would expand takeaway capacity by 4.2 Bcf/d by the end of 2024.
- International futures prices: International natural gas futures prices declined this report week. According to Bloomberg Finance, L.P., weekly average futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased $9.23 to a weekly average of $43.97/MMBtu, and natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased $4.18 to a weekly average of $56.63/MMBtu.
- Natural gas plant liquids prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 54 cents/MMBtu, averaging $9.89/MMBtu for the week ending September 21. The price of ethane fell 10%, more than the natural gas price at the Houston Ship Channel, which fell 7%. Ethane moved to a 15 cents/MMBtu discount to natural gas this report week, compared with a 9 cents/MMBtu premium for the week ending September 14. The price of ethylene fell 3%, widening the ethylene to ethane premium by 15%. The propane price fell 4%, while the Brent crude oil price fell 2%, resulting in the propane discount to crude oil increasing by 4%. The price of normal butane and isobutane both fell 3%, and the natural gasoline price remained relatively unchanged.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from PointLogic, the average total supply of natural gas rose by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.6% (0.6 Bcf/d), and net imports from Canada increased by 12.7% (0.7 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas fell by 1.0% (0.7 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation declined by 1.1% (0.4 Bcf/d) week over week, and industrial sector consumption decreased by 1.8% (0.4 Bcf/d). In the residential and commercial sectors, consumption increased by 1.0% (0.1 Bcf/d). Natural gas exports to Mexico decreased 5.9% (0.3 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.6 Bcf/d, or 0.4 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Natural gas deliveries to LNG export terminals in South Texas increased by 0.3 Bcf/d this week to an average of 2.3 Bcf/d, according to data from PointLogic. Deliveries to LNG export terminals in South Louisiana increased by 0.1 Bcf/d to 8.2 Bcf/d. Natural gas deliveries to other LNG export terminals were essentially flat week over week. Overall natural gas deliveries to U.S. LNG export terminals increased by 0.4 Bcf/d to an average of 11.6 Bcf/d this report week.
- Vessels departing U.S. ports: Twenty-one LNG vessels (seven from Sabine Pass, four from Corpus Christi, three each from Cameron and Calcasieu Pass, and two each from Cove Point and Elba Island) with a combined LNG-carrying capacity of 79 Bcf departed the United States between September 15 and September 21, according to shipping data provided by Bloomberg Finance, L.P.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, September 13, the natural gas rig count decreased by 4 rigs from a week ago to 162 rigs. The Arkoma Woodford, the Barnett, the Eagle Ford, and an unspecified producing region each dropped one rig. The number of oil-directed rigs increased by 8 rigs from a week ago to 599 rigs. The Arkoma Woodford and the Barnett added one rig each. The Cana Woodford and the Eagle Ford added two rigs each, and the Permian added three rigs. One rig was dropped in the Williston. The total rig count, which includes 2 miscellaneous rigs, now stands at 763 rigs, which is 251 more rigs than the same week last year.
Storage
- The net injections into storage totaled 103 Bcf for the week ending September 16, compared with the five-year (2017–2021) average net injections of 81 Bcf and last year's net injections of 77 Bcf during the same week. Working natural gas stocks totaled 2,874 Bcf, which is 332 Bcf (10%) lower than the five-year average and 197 Bcf (6%) lower than last year at this time.
- According to The Desk survey natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net injections of 90 Bcf to 104 Bcf, with a median estimate of 97 Bcf.
- The average rate of injections into storage is 3% 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 9.7 Bcf/d for the remainder of the refill season, the total inventory would be 3,313 Bcf on October 31, which is 332 Bcf lower than the five-year average of 3,645 Bcf for that time of year.
Other Market Drivers
- Texas Eastern Transmission, LP (TE) provided an updated notice regarding an unplanned outage and force majeure experienced on TE Line 73 between Salineville compressor station in Columbiana County, Ohio, and Colerain compressor station in Jefferson County, Ohio, that has reduced capacity through the Salineville compressor station to zero until further notice. TE reports that a timeframe for return to service remains unclear, but it anticipates that it will not be able to return the pipeline to service before September 28.
See also:
Data source: U.S. Energy Information Administration
Note: LNG=liquefied natural gas
Data source: U.S. Energy Information Administration
Note: LNG=liquefied natural gas
Data source: U.S. Energy Information Administration
Note: LNG=liquefied natural gas
| Spot Prices ($/MMBtu) | Thu, 15-Sep |
Fri, 16-Sep |
Mon, 19-Sep |
Tue, 20-Sep |
Wed, 21-Sep |
|---|---|---|---|---|---|
| Henry Hub |
8.51 |
8.07 |
7.85 |
7.95 |
7.99 |
| New York |
7.37 |
6.84 |
7.05 |
6.92 |
5.95 |
| Chicago |
7.67 |
6.94 |
6.99 |
7.00 |
6.82 |
| Cal. Comp. Avg.* |
8.33 |
7.54 |
7.73 |
7.53 |
7.51 |
| Futures ($/MMBtu) | |||||
| October contract | 8.324 |
7.764 |
7.752 |
7.717 |
7.779 |
| November contract |
8.372 |
7.811 |
7.804 |
7.772 |
7.827 |
| 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. |
|||||
| U.S. natural gas supply - Gas Week: (9/15/22 - 9/21/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 110.5 |
111.0 |
106.8 |
| Dry production | 98.8 |
99.4 |
94.1 |
| Net Canada imports | 6.0 |
5.3 |
4.8 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 104.9 |
104.8 |
98.9 |
|
Data source: PointLogic | |||
| U.S. natural gas consumption - Gas Week: (9/15/22 - 9/21/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 66.7 |
67.4 |
64.3 |
| Power | 36.4 |
36.8 |
34.9 |
| Industrial | 21.4 |
21.8 |
20.7 |
| Residential/commercial | 9.0 |
8.9 |
8.7 |
| Mexico exports | 5.3 |
5.6 |
5.9 |
| Pipeline fuel use/losses | 6.6 |
6.7 |
6.3 |
| LNG pipeline receipts | 11.6 |
11.2 |
9.6 |
| Total demand | 90.2 |
90.8 |
86.1 |
|
Data source: PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, September 13, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 599 |
1.4% |
45.7% |
| Natural gas rigs | 162 |
-2.4% |
62.0% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, September 13, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 23 |
-4.2% |
-20.7% |
| Horizontal | 695 |
0.4% |
49.1% |
| Directional | 45 |
4.7% |
164.7% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2022-09-16 |
2022-09-09 |
change |
|
| East | 690 |
661 |
29 |
|
| Midwest | 844 |
809 |
35 |
|
| Mountain | 168 |
163 |
5 |
|
| Pacific | 237 |
235 |
2 |
|
| South Central | 935 |
904 |
31 |
|
| Total | 2,874 |
2,771 |
103 |
|
| 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 (9/16/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 748 |
-7.8 |
784 |
-12.0 |
|
| Midwest | 900 |
-6.2 |
907 |
-6.9 |
|
| Mountain | 196 |
-14.3 |
199 |
-15.6 |
|
| Pacific | 240 |
-1.3 |
278 |
-14.7 |
|
| South Central | 986 |
-5.2 |
1,038 |
-9.9 |
|
| Total | 3,071 |
-6.4 |
3,206 |
-10.4 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Sep 15) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 7 |
-16 |
0 |
18 |
12 |
-1 |
||
| Middle Atlantic | 6 |
-10 |
2 |
24 |
8 |
-7 |
||
| E N Central | 16 |
-4 |
7 |
14 |
-2 |
-19 |
||
| W N Central | 20 |
-7 |
8 |
22 |
-1 |
-19 |
||
| South Atlantic | 1 |
-1 |
1 |
67 |
1 |
-6 |
||
| E S Central | 4 |
1 |
2 |
47 |
-7 |
-9 |
||
| W S Central | 1 |
-1 |
1 |
77 |
-11 |
-8 |
||
| Mountain | 22 |
-8 |
19 |
37 |
-6 |
-29 |
||
| Pacific | 2 |
-7 |
-2 |
43 |
10 |
-11 |
||
| United States | 9 |
-6 |
4 |
41 |
1 |
-12 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Sep 15, 2022
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Sep 15, 2022
Data source: National Oceanic and Atmospheric Administration
