In the News:
Natural gas deliveries to U.S. LNG export facilities increased in the first half of 2023
Natural gas deliveries by pipeline to U.S. liquefied natural gas (LNG) export facilities (LNG feed gas) averaged 12.8 billion cubic feet per day (Bcf/d) in the first six months of 2023, following the Freeport LNG terminal’s return to service, according to data by S&P Global Commodity Insights. This average was 1.0 Bcf/d (8%) more than the 2022 annual average and 0.5 Bcf/d (4%) more than the same six-month period in 2022.
LNG feed gas set a monthly record in April 2023 at 14.0 Bcf/d, supported by high international demand for U.S. LNG exports, particularly in Europe. However, LNG feed gas declined in May (13.0 Bcf/d) and June (11.5 Bcf/d), mostly due to maintenance at several U.S. LNG export facilities, including Sabine Pass and Cameron.
LNG feed gas levels are typically higher than LNG export levels because LNG export terminals consume some of the feed gas to operate on-site liquefaction equipment. All U.S. LNG export facilities, except Freeport LNG, use natural gas turbine-driven refrigerant compressors to convert natural gas from a gaseous to a liquid state, or LNG.
We capture the differences in LNG feed gas and LNG export levels under the Pipeline & Distribution Use category in our Natural Gas Monthly. In addition to LNG feed gas used during the liquefaction process at LNG facilities, the Pipeline & Distribution Use category also includes natural gas consumed in pipeline transportation. We estimate that approximately 14% of LNG feed gas is used for liquefaction processes, to operate on-site liquefaction equipment. In our Short-Term Energy Outlook (STEO), we account for feed gas used in the liquefaction process and natural gas consumed in pipeline transportation in the Natural Gas Pipeline and Distribution Use category in Table 5a. U.S. Natural Gas Supply, Consumption, and Inventories.
Freeport LNG is the only liquefaction facility in the United States and one of only two LNG export facilities in the world that uses electric motors exclusively instead of natural gas turbines to drive the liquefaction compressors. Using electric motors helps the facility comply with the local air emission standards around the Houston area—the location of Freeport LNG. Freeport LNG purchases electricity from the grid to power its liquefaction processes because it does not have an on-site natural gas-fired power plant. As a result, most of Freeport LNG’s feed gas is converted into LNG.
We forecast U.S. LNG exports to average 12.0 Bcf/d in 2023 and 13.3 Bcf/d in 2024, as two new LNG liquefaction projects are expected to come online—Golden Pass and Plaquemines, according to our July 2023 STEO. Global economic conditions and demand for natural gas in Europe and Asia may affect our forecast. Trends supporting higher LNG exports from the United States include assumed continuous replacement of Russia's natural gas exports by pipeline to Europe. Limited growth in global LNG export capacity in the next two years may increase the need for destination-flexible LNG supplies, mainly from the United States. So far this year, mild winter temperatures and above-average storage inventories in the northern hemisphere decreased spot LNG prices, which could be an incentive to import more LNG, particularly in the relatively more price-sensitive countries of Southeast Asia.
For more information on our forecast of U.S. LNG exports, refer to our recently released STEO Between the Lines report.
Market Highlights:
(For the week ending Wednesday, July 12, 2023)Prices
- Henry Hub spot price: The Henry Hub spot price fell 9 cents from $2.64 per million British thermal units (MMBtu) last Wednesday to $2.55/MMBtu yesterday.
- Henry Hub futures prices: The price of the August 2023 NYMEX contract decreased 2.5 cents, from $2.657/MMBtu last Wednesday to $2.632/MMBtu yesterday. The price of the 12-month strip averaging August 2023 through July 2024 futures contracts declined 2.8 cents to $3.181/MMBtu.
- Select regional spot prices: Natural gas spot price changes were mixed at major pricing hubs this report week (Wednesday, July 5, to Wednesday, July 12). Price changes ranged from a decrease of $6.06/MMBtu at Algonquin Citygate to an increase of $0.63/MMBtu at Tennessee Zone 4 Marcellus.
- At the Algonquin Citygate, which serves Boston-area consumers, the price went down $6.06 from $7.93/MMBtu last Wednesday to $1.87/MMBtu yesterday, returning to levels more in line with other prices in the region. Algonquin Gas Transmission completed maintenance on Sunday that resulted in increased natural gas flows into New England. In addition, Units 2 and 3 of Millstone Power Station, a 2,108 MW-nuclear power plant in Waterford, Connecticut, resumed operating at full capacity as of July 6, after being offline for much of June, reducing demand for natural gas-fired generation. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 8 cents from $1.87/MMBtu last Wednesday to $1.79/MMBtu yesterday.
- In the Appalachian production region, spot prices rose. The Tennessee Zone 4 Marcellus spot price increased 63 cents from $0.92/MMBtu last Wednesday—the fifth time this year the price fell below $1.00/MMBtu—to $1.55/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania increased 20 cents from $1.44/MMBtu last Wednesday to $1.64/MMBtu yesterday. Natural gas flows from Appalachia to New York and New Jersey increased 7%, or 0.5 billion cubic feet per day (Bcf/d) week over week, according to data from S&P Global Commodity Insights. Temperatures in the New York-Central Park Area averaged 80°F this week, resulting in 16 more cooling degree days (CDDs) than last week and 22 more CDDs than normal.
- Prices increased in most West Coast markets this week, except at SoCal Citygate in Southern California, where the price decreased 45 cents from $3.85/MMBtu last Wednesday to $3.40/MMBtu yesterday. Natural gas consumption in California declined 8% (0.4 Bcf/d) week over week, led by a 26% (0.5 Bcf/d) decrease in consumption in the electric power sector, according to data from S&P Global Commodity Insights. Temperatures in the Riverside Area, inland from Los Angeles, averaged 76°F this week, resulting in 3 fewer CDDs than last week and 11 fewer CDDs than normal. The share of natural gas used for power generation in California decreased from 42% last week to 36% this week, while the share of wind, solar, and hydroelectric power generation combined increased from 47% last week to 52% this week, according to our Hourly Electric Grid Monitor. The Southern California Gas Company’s (SoCalGas) natural gas storage stocks were almost 73 Bcf, very near the five-year (2018–2022) average, on July 13. The price in Northern California rose this week, along with other West Coast pricing hubs. At PG&E Citygate in Northern California, the price rose 36 cents, up from $3.96/MMBtu last Wednesday to $4.32/MMBtu yesterday.
- In the Pacific Northwest, the price at Sumas on the Canada-Washington border rose 59 cents from $2.27/MMBtu last Wednesday to $2.86/MMBtu yesterday. At Malin, Oregon, the northern delivery point into the PG&E service territory, the price rose 25 cents from $2.63/MMBtu last Wednesday to $2.88/MMBtu yesterday. Capacity reductions occurred on the two major feeder lines from Canada into the Pacific Northwest. Gas Transmission Northwest declared force majeure due to unexpected equipment failure at its Starbuck compressor station in southeastern Washington, which reduced available capacity by approximately 0.4 Bcf/d at the Flow Past Kingsgate delivery point in Boundary, Idaho. On the Westcoast Energy Inc. pipeline, which delivers natural gas from British Columbia into Washington, available capacity was reduced by 0.5 Bcf/d on July 12.
- International futures prices: International natural gas futures prices decreased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased 9 cents to a weekly average of $12.04/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased $1.43 to a weekly average of $9.78/MMBtu. In the same week last year (week ending July 13, 2022), the prices were $39.13/MMBtu in East Asia and $51.88/MMBtu at TTF. Forward prices were higher in East Asia compared with TTF for August–October as of July 12, according to Bloomberg Finance, L.P.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 54 cents/MMBtu, averaging $6.25/MMBtu for the week ending July 12. Weekly average ethane prices rose 11%, while natural gas prices at the Houston Ship Channel rose by 1%, resulting in an increase of the ethane premium to natural gas by 27% week over week. Ethylene spot prices rose 2%, decreasing the ethylene to ethane premium by 7%. Propane prices rose 10%, while the Brent crude oil price rose 4%, decreasing the propane discount relative to crude oil by 1%. The normal butane price rose 10%, the isobutane price rose 8%, and the natural gasoline price rose 8%.
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 fell by 0.5% (0.5 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.1% (0.1 Bcf/d) to 101.8 Bcf/d, and average net imports from Canada decreased by 6.6% (0.4 Bcf/d) from last week to 5.5 Bcf/d.
- Demand: Total U.S. consumption of natural gas fell by 2.2% (1.6 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 2.8% (1.2 Bcf/d) week over week. Industrial sector consumption was essentially unchanged, and in the residential and commercial sectors, consumption declined by 4.1% (0.4 Bcf/d). Natural gas exports to Mexico decreased 1.5% (0.1 Bcf/d), and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.4 Bcf/d, or 0.4 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Overall weekly average natural gas deliveries to U.S. LNG export terminals decreased by 2.7% (0.4 Bcf/d) week over week to average 12.4 Bcf/d this report week, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Texas decreased by 3.5% (0.1 Bcf/d) to 3.9 Bcf/d, while deliveries to terminals in South Louisiana decreased by 3.3% (0.2 Bcf/d) to 7.4 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-four LNG vessels (eight from Sabine Pass, four each from Cameron and Freeport, three from Corpus Christi, two each from Calcasieu Pass and Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 90 Bcf departed the United States between July 6 and July 12, according to shipping data provided by Bloomberg Finance, L.P.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, July 4, the natural gas rig count increased by 11 rigs from a week ago to 135 rigs. The Permian added seven rigs, the Haynesville added two rigs, and two rigs were added in unidentified producing basins. The number of oil-directed rigs decreased by 5 rigs from a week ago to 540 rigs. The Permian dropped six rigs, the Eagle Ford dropped one rig, and two rigs were added in unidentified producing basins. The total rig count, which includes 5 miscellaneous rigs, stands at 680 rigs, 72 fewer rigs than last year at this time.
Storage
- The net injections into storage totaled 49 Bcf for the week ending July 7, compared with the five-year (2018–2022) average net injections of 55 Bcf and last year's net injections of 59 Bcf during the same week. Working natural gas stocks totaled 2,930 Bcf, which is 364 Bcf (14%) more than the five-year average and 569 Bcf (24%) 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 41 Bcf to 59 Bcf, with a median estimate of 49 Bcf.
- The average rate of injections into storage is 6% higher 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 8.9 Bcf/d for the remainder of the refill season, the total inventory would be 3,959 Bcf on October 31, which is 364 Bcf higher than the five-year average of 3,595 Bcf for that time of year.
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Data source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), and S&P Global Commodity Insights Note: LNG=liquefied natural gas. LNG feed gas=natural gas delivered by pipelines to LNG export terminals.
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), and S&P Global Commodity Insights Note: LNG=liquefied natural gas. LNG feed gas=natural gas delivered by pipelines to LNG export terminals. Six terminals include Sabine Pass, Corpus Christi, Cove Point, Elba Island, Cameron, and Calcasieu Pass LNG export terminals.
| Spot Prices ($/MMBtu) | Thu, 06-Jul |
Fri, 07-Jul |
Mon, 10-Jul |
Tue, 11-Jul |
Wed, 12-Jul |
|---|---|---|---|---|---|
| Henry Hub |
2.52 |
2.49 |
2.57 |
2.59 |
2.55 |
| New York |
1.65 |
1.55 |
1.81 |
2.06 |
1.79 |
| Chicago |
2.15 |
2.05 |
2.31 |
2.40 |
2.37 |
| Cal. Comp. Avg.* |
2.97 |
2.42 |
3.44 |
3.43 |
3.46 |
| Futures ($/MMBtu) | |||||
| August contract | 2.609 |
2.582 |
2.669 |
2.731 |
2.632 |
| September contract |
2.599 |
2.570 |
2.641 |
2.692 |
2.597 |
| *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: (7/6/23 - 7/12/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 114.4 |
114.5 |
111.5 |
| Dry production | 101.8 |
102.0 |
98.6 |
| Net Canada imports | 5.5 |
5.9 |
5.8 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.0 |
| Total supply | 107.4 |
108.0 |
104.4 |
|
Data source: S&P Global Commodity Insights | |||
| U.S. natural gas consumption - Gas Week: (7/6/23 - 7/12/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 72.4 |
74.0 |
73.2 |
| Power | 42.6 |
43.8 |
44.0 |
| Industrial | 21.3 |
21.3 |
20.9 |
| Residential/commercial | 8.5 |
8.9 |
8.2 |
| Mexico exports | 6.5 |
6.6 |
6.1 |
| Pipeline fuel use/losses | 7.0 |
7.0 |
6.8 |
| LNG pipeline receipts | 12.4 |
12.8 |
11.1 |
| Total demand | 98.2 |
100.3 |
97.2 |
|
Data source: S&P Global Commodity Insights | |||
| Rigs | |||
|---|---|---|---|
Tue, July 04, 2023 |
Change from |
||
last week |
last year |
||
| Oil rigs | 540 |
-0.9% |
-9.5% |
| Natural gas rigs | 135 |
8.9% |
-11.8% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, July 04, 2023 |
Change from |
||
last week |
last year |
||
| Vertical | 16 |
-11.1% |
-40.7% |
| Horizontal | 611 |
0.8% |
-10.4% |
| Directional | 53 |
6.0% |
23.3% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2023-07-07 |
2023-06-30 |
change |
|
| East | 653 |
643 |
10 |
|
| Midwest | 724 |
705 |
19 |
|
| Mountain | 180 |
173 |
7 |
|
| Pacific | 225 |
216 |
9 |
|
| South Central | 1,147 |
1,144 R |
3 |
|
| Total | 2,930 |
2,881 R |
49 |
|
|
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. R=Revised The reported revision caused the stocks for June 30, 2023 to change from 2,877 Bcf to 2,881 Bcf. As a result, the implied net change between the weeks ending June 23 and June 30 changed from 72 Bcf to 76 Bcf. | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (7/7/22) |
5-year average (2018-2022) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 498 |
31.1 |
547 |
19.4 |
|
| Midwest | 583 |
24.2 |
619 |
17.0 |
|
| Mountain | 142 |
26.8 |
158 |
13.9 |
|
| Pacific | 248 |
-9.3 |
266 |
-15.4 |
|
| South Central | 890 |
28.9 |
976 |
17.5 |
|
| Total | 2,361 |
24.1 |
2,566 |
14.2 |
|
| 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 Jul 06) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 0 |
-2 |
-1 |
55 |
23 |
11 |
||
| Middle Atlantic | 0 |
0 |
0 |
74 |
26 |
14 |
||
| E N Central | 0 |
-1 |
0 |
71 |
21 |
5 |
||
| W N Central | 3 |
-1 |
3 |
65 |
1 |
-11 |
||
| South Atlantic | 0 |
0 |
0 |
107 |
15 |
3 |
||
| E S Central | 0 |
0 |
0 |
104 |
16 |
-5 |
||
| W S Central | 0 |
0 |
0 |
129 |
11 |
-5 |
||
| Mountain | 6 |
-3 |
5 |
73 |
1 |
0 |
||
| Pacific | 0 |
-6 |
-3 |
53 |
17 |
23 |
||
| United States | 1 |
-2 |
0 |
83 |
16 |
6 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Jul 06, 2023
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Jul 06, 2023
Data source: National Oceanic and Atmospheric Administration
