In the News:
The United States exported more liquefied natural gas than any other country in the first six months of 2023
The United States exported more liquefied natural gas (LNG) than any other LNG-exporting country in the first six months of 2023, according to data from CEDIGAZ. U.S. LNG exports averaged 11.6 billion cubic feet per day (Bcf/d) during this period, 4% (0.5 Bcf/d) higher than the first half of last year and 9.5% (1.0 Bcf/d) higher than the 2022 annual average, according to data from the U.S. Department of Energy’s LNG Reports. Australia was the world’s second-largest LNG exporter in the first half of 2023, with LNG exports averaging 10.6 Bcf/d during this period, followed by Qatar at 10.4 Bcf/d. The increase in LNG exports from the United States was mainly the result of Freeport LNG’s return to service and continued growth in global LNG demand, particularly in Europe.
As in 2022, Europe (the European Union [EU-27] plus the UK) remained the main destination for U.S. LNG exports in the first half of 2023, accounting for 67% (7.7 Bcf/d) of total U.S. exports. U.S. LNG exports to Europe increased by 14% (1.0 Bcf/d) compared with the 2022 annual average. Five countries—the Netherlands, the UK, France, Spain, and Germany—accounted for 77% (6.0 Bcf/d) of total U.S. LNG exports to Europe.
U.S. LNG exports set an all-time monthly record high of 12.4 Bcf/d in April as Freeport LNG ramped up LNG production and Europe continued to increase LNG imports to compensate for lower pipeline imports from Russia and to refill storage inventories. Europe’s regasification capacity continued to expand in 2023 as new terminals were placed in service in Finland, Germany, Italy, and Spain, allowing those countries to import more LNG. After a mild winter, Europe ended the 2022–23 heating season with the most natural gas in storage on record, but it still relied on LNG and was refilling its storage inventories at a rapid pace in the spring and summer.
In the first six months of this year, Europe’s LNG imports exceeded imports by pipeline for the first time on record, according to data from Refinitiv Eikon. Europe’s LNG imports averaged 15.9 Bcf/d, 0.1 Bcf/d higher than imports by pipeline from all sources, including Norway, Russia, Algeria, Libya, and Azerbaijan. In 2022, LNG imports averaged 14.9 Bcf/d annually, which was 28% (5.8 Bcf/d) below natural gas imports by pipeline. Europe’s LNG imports peaked in April 2023 at 18.0 Bcf/d and remained above natural gas imports by pipeline from April through June 2023.
We estimate that utilization of the peak capacity at the seven U.S. LNG export facilities averaged 83% during the first half of 2023, compared with 88% during the first half of 2022 and 80% for all of 2022. Lower utilization in the first half 2023 reflects the ramping-up period at Freeport LNG, which restarted LNG exports in February.
Market Highlights:
(For the week ending Wednesday, August 23, 2023)Prices
- Henry Hub spot price: The Henry Hub spot price rose 4 cents from $2.55 per million British thermal units (MMBtu) last Wednesday to $2.59/MMBtu yesterday.
- Henry Hub futures price: The price of the September 2023 NYMEX contract decreased 9.5 cents, from $2.592/MMBtu last Wednesday to $2.497/MMBtu yesterday. The price of the 12-month strip averaging September 2023 through August 2024 futures contracts declined 11.5 cents to $3.224/MMBtu.
- Select regional spot prices: Natural gas spot prices decreased at most major pricing hubs this report week (Wednesday, August 16, to Wednesday, August 23). Price decreases this week ranged from $4.22/MMBtu at SoCal Citygate to $0.04/MMBtu at Chicago Citygate.
- Prices in West Coast markets decreased this week. The price at SoCal Citygate in Southern California decreased $4.22 from $7.80/MMBtu last Wednesday to $3.58/MMBtu yesterday, and the price at PG&E Citygate in Northern California fell $1.50 from $5.64/MMBtu last Wednesday to $4.14/MMBtu yesterday. The tropical storm that landed over the northern Baja California Peninsula in Mexico on Sunday brought rain and cooler temperatures to Southern California. Temperatures in the Riverside Area, east of Los Angeles, averaged 79°F this week, resulting in 96 cooling degree days (CDD), 16 fewer CDDs than last week and 8 fewer than normal. Natural gas consumption in the electric power sector in California decreased 10%, or 0.3 billion cubic feet per day (Bcf/d), week over week, according to data from S&P Global Commodity Insights. The Aliso Canyon storage facility in Southern California, with capacity of 41 billion cubic feet (Bcf), has been full since August 14, according to Southern California Gas Company (SoCalGas).
- In the Midwest, the Chicago Citygate price decreased 4 cents from $2.38/MMBtu last Wednesday to $2.34/MMBtu yesterday despite an 8% (0.8 Bcf/d) increase in natural gas consumption, according to data from S&P Global Insights. The increased consumption was driven by a 14% (0.5 Bcf/d) increase in consumption in the electric power sector. Above-average temperatures in the second half of this report week in the Chicago Area resulted in 85 CDDs, 25 more CDDs than normal and 23 more than last week. A daily record high of 98°F was recorded yesterday in the Chicago Area.
- In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price went down 21 cents from $1.50/MMBtu last Wednesday to $1.29/MMBtu yesterday. In the Boston Area, temperatures averaged 71°F this week, resulting in 12 fewer CDDs than normal and 29 fewer than last week. Natural gas consumption in the electric power sector in New England decreased 10% (0.1 Bcf/d) week over week. The Tennessee Zone 4 Marcellus spot price decreased 31 cents from $1.18/MMBtu last Wednesday to $0.87/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell 20 cents from $1.24/MMBtu last Wednesday to $1.04/MMBtu yesterday. Maintenance on Tennessee Gas Pipeline has reduced natural gas flows out of the region. See Other Market Drivers section for more details.
- International futures prices: International natural gas futures prices increased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia increased $2.33 to a weekly average of $14.09/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands increased 60 cents to a weekly average of $12.35/MMBtu. In the same week last year (week ending August 24, 2022), the prices were $59.01/MMBtu in East Asia and $77.60/MMBtu at TTF.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 19 cents/MMBtu, averaging $6.75/MMBtu for the week ending August 23. Weekly average ethane prices rose 3%, while natural gas prices at the Houston Ship Channel fell by 4%, widening the ethane premium to natural gas by 15% week over week. Ethylene spot prices rose 2%, widening the ethylene premium to ethane by 1%. The propane price fell 5%, while the Brent crude oil price fell 2%, increasing the propane discount relative to crude oil by 1%. The normal butane price fell 4%, the isobutane price fell 10%, and the natural gasoline price fell 1%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 0.5% (0.5 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.5% (0.5 Bcf/d) to average 102.5 Bcf/d, and average net imports from Canada increased by 0.5% (less than 0.1 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas fell by 0.3% (0.2 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation declined by 1.0% (0.5 Bcf/d) week over week. Industrial sector consumption decreased by 0.4% (0.1 Bcf/d) and residential and commercial sector consumption increased by 3.9% (0.3 Bcf/d). Natural gas exports to Mexico increased 1.3% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.9 Bcf/d, or 0.3 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals decreased by 2.8% (0.3 Bcf/d) week over week, averaging 11.9 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Texas decreased by 5.0% (0.2 Bcf/d) to 3.7 Bcf/d, while deliveries to terminals in South Louisiana decreased by 2.1% (0.2 Bcf/d) to 7.1 Bcf/d. Natural gas deliveries to terminals outside the Gulf Coast were essentially unchanged at 1.1 Bcf/d.
- Vessels departing U.S. ports: Twenty LNG vessels (seven from Sabine Pass; three each from Cameron, Corpus Christi, and Freeport; two from Calcasieu Pass; and one each from Cove Point and Elba Island) with a combined LNG-carrying capacity of 72 Bcf departed the United States between August 17 and August 23, according to shipping data provided by Bloomberg Finance, L.P.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, August 15, the natural gas rig count decreased by 6 rigs from a week ago to 117 rigs. The Haynesville and the Permian dropped one rig each, the Utica dropped two rigs, and two rigs were dropped among unidentified producing basins. The number of oil-directed rigs decreased by 5 from a week ago to 520 rigs. The Granite Wash and the Permian added one rig each, the Cana Woodford dropped three rigs, the Williston dropped two rigs, and two rigs were dropped among unidentified producing basins. The total rig count, which includes 5 miscellaneous rigs, stands at 642 rigs, 120 fewer rigs than last year at this time.
Storage
- Net injections into storage totaled 18 Bcf for the week ending August 18, compared with the five-year (2018–2022) average net injections of 49 Bcf and last year's net injections of 54 Bcf during the same week. Working natural gas stocks totaled 3,083 Bcf, which is 268 Bcf (10%) more than the five-year average and 513 Bcf (20%) more 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 25 Bcf to 39 Bcf, with a median estimate of 31 Bcf.
- The average rate of injections into storage is 2% 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 10.5 Bcf/d for the remainder of the refill season, the total inventory would be 3,863 Bcf on October 31, which is 268 Bcf higher than the five-year average of 3,595 Bcf for that time of year.
Other Market Drivers
- Tennessee Gas Pipeline Company issued operational flow orders and imbalance warnings on its system this week, indicating limits to natural gas deliveries out of the Appalachian Basin. According to the notices, scheduled maintenance and nominations in excess of operational capacity have restricted deliveries through several compressor stations, including station 321 in Susquehanna County in Pennsylvania, where volumes have been restricted by approximately 0.2 Bcf/d–0.4 Bcf/d during several days this week.
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Data source: International Group of Liquefied Natural Gas Importers (2018–2021) and CEDIGAZ (2022–1H2023) Note: 1H2023=six months (Jan–Jun) 2023. Data are annual averages for 2018–2022 and six-month (Jan–Jun) average for 2023.
Data source: U.S. Department of Energy, LNG Reports Note: 1H2023=six months (Jan–Jun) 2023. Data are annual averages for 2021 and 2022 and six-month (Jan–Jun) average for 2023.
Data source: U.S. Energy Information Administration, Liquefaction Capacity Table and U.S. Department of Energy, LNG Reports Note: Daily utilization of U.S. LNG export capacity is calculated as a 30-day moving average. For Sabine Pass and Corpus Christi LNG facilities, uprated capacities of 4.6 Bcf/d and 2.4 Bcf/d, respectively, starting in October 2021 (based on FERC orders) were used in calculations.
| Spot Prices ($/MMBtu) | Thu, 17-Aug |
Fri, 18-Aug |
Mon, 21-Aug |
Tue, 22-Aug |
Wed, 23-Aug |
|---|---|---|---|---|---|
| Henry Hub |
2.56 |
2.45 |
2.58 |
2.61 |
2.59 |
| New York |
1.27 |
1.24 |
1.30 |
1.29 |
1.19 |
| Chicago |
2.37 |
2.27 |
2.41 |
2.43 |
2.34 |
| Cal. Comp. Avg.* |
4.28 |
3.81 |
3.77 |
3.24 |
3.04 |
| Futures ($/MMBtu) | |||||
| September contract | 2.621 |
2.551 |
2.632 |
2.560 |
2.497 |
| October contract |
2.755 |
2.691 |
2.743 |
2.652 |
2.592 |
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Data source: NGI's Daily Gas Price Index | |||||
| U.S. natural gas supply - Gas Week: (8/17/23 - 8/23/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 115.2 |
114.6 |
111.2 |
| Dry production | 102.5 |
102.0 |
98.3 |
| Net Canada imports | 6.0 |
6.0 |
4.9 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 108.5 |
108.0 |
103.3 |
|
Data source: S&P Global Commodity Insights | |||
| U.S. natural gas consumption - Gas Week: (8/17/23 - 8/23/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 74.5 |
74.7 |
70.5 |
| Power | 44.5 |
44.9 |
41.3 |
| Industrial | 21.4 |
21.5 |
21.5 |
| Residential/commercial | 8.7 |
8.4 |
7.7 |
| Mexico exports | 6.1 |
6.0 |
5.8 |
| Pipeline fuel use/losses | 7.1 |
7.0 |
6.7 |
| LNG pipeline receipts | 11.9 |
12.2 |
10.9 |
| Total demand | 99.6 |
100.0 |
94.0 |
|
Data source: S&P Global Commodity Insights | |||
| Rigs | |||
|---|---|---|---|
Tue, August 15, 2023 |
Change from |
||
last week |
last year |
||
| Oil rigs | 520 |
-1.0% |
-13.5% |
| Natural gas rigs | 117 |
-4.9% |
-26.4% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, August 15, 2023 |
Change from |
||
last week |
last year |
||
| Vertical | 18 |
-18.2% |
-37.9% |
| Horizontal | 572 |
-1.2% |
-17.6% |
| Directional | 52 |
-1.9% |
33.3% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2023-08-18 |
2023-08-11 |
change |
|
| East | 731 |
717 |
14 |
|
| Midwest | 831 |
812 |
19 |
|
| Mountain | 206 |
202 |
4 |
|
| Pacific | 242 |
240 |
2 |
|
| South Central | 1,072 |
1,093 |
-21 |
|
| Total | 3,083 |
3,065 |
18 |
|
|
Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report
Note: Totals may not equal sum of components because of independent rounding. | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (8/18/22) |
5-year average (2018-2022) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 594 |
23.1 |
659 |
10.9 |
|
| Midwest | 710 |
17.0 |
759 |
9.5 |
|
| Mountain | 153 |
34.6 |
175 |
17.7 |
|
| Pacific | 244 |
-0.8 |
261 |
-7.3 |
|
| South Central | 870 |
23.2 |
960 |
11.7 |
|
| Total | 2,570 |
20.0 |
2,815 |
9.5 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report
Note: Totals may not equal sum of components because of independent rounding. |
|||||
| Temperature – heating & cooling degree days (week ending Aug 17) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 1 |
-3 |
-2 |
33 |
-3 |
6 |
||
| Middle Atlantic | 0 |
-3 |
-3 |
55 |
5 |
16 |
||
| E N Central | 4 |
-1 |
-4 |
35 |
-12 |
11 |
||
| W N Central | 4 |
0 |
2 |
46 |
-15 |
-7 |
||
| South Atlantic | 0 |
0 |
0 |
107 |
16 |
27 |
||
| E S Central | 0 |
0 |
0 |
91 |
3 |
15 |
||
| W S Central | 0 |
0 |
0 |
146 |
24 |
18 |
||
| Mountain | 1 |
-4 |
1 |
78 |
8 |
4 |
||
| Pacific | 0 |
-3 |
0 |
70 |
26 |
-3 |
||
| United States | 2 |
-2 |
-1 |
76 |
8 |
12 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Aug 17, 2023
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Aug 17, 2023
Data source: National Oceanic and Atmospheric Administration
