In the News:
Freeport LNG becomes the fifth export terminal in Lower 48 states to begin operations
On September 3, 2019, Freeport LNG Development L.P.—the developer of Freeport LNG export terminal—announced the first shipment of liquefied natural gas (LNG) produced from the newly commissioned Train 1 of the three-train Freeport LNG facility. Freeport LNG became the fifth U.S. LNG export terminal in the Lower 48 states to be placed in service since 2016.
Freeport LNG liquefaction project is located on Quintana Island near Freeport, Texas―about 70 miles south of Houston― and consists of three liquefaction units (called trains) with a combined capacity of 1.98 billion cubic feet per day (Bcf/d) baseload (2.14 Bcf/d peak capacity). Construction of Trains 1 and 2 started in 2014, and construction of Train 3 in 2015. After a series of construction delays, Train 1 achieved its first LNG production on August 19. The second and third trains are expected to be placed in service in January 2020 and May 2020, respectively. The fourth liquefaction train (capacity 0.7 Bcf/d) has been fully approved, but has not yet reached a final investment decision.
The Freeport LNG liquefaction plant is located at the site of an existing regasification (import) terminal and shares LNG storage tanks and other infrastructure with export and import facilities, which reduces the construction costs. The Freeport LNG regasification terminal can still receive and process LNG import cargoes; however, it has been mostly unused since 2010 because of the increase in domestic natural gas production. The last LNG cargo was imported to Freeport in September 2018 and was used to maintain the cryogenic integrity of the terminal’s storage tanks and to serve as a cool down cargo in preparation and testing of liquefaction equipment for LNG production.
Freeport LNG is the only liquefaction facility in the United States and one of only two LNG export facilities in the world that uses exclusively electric motors instead of natural gas turbines to drive the liquefaction compressors. The electric motors help the facility comply with the strict local emission standards around the Houston area. Freeport LNG requires 690 megawatts (MW) of electric power supply to operate three liquefaction trains, almost 9 times the Freeport area’s previous load, which was less than 80 MW. Several electric transmission upgrades (including Jones Creek transmission project) were implemented on the Electric Reliability Council of Texas electric power grid to connect transmission lines with Freeport LNG to accommodate the additional load requirements.
Currently, with Freeport Train 1 in operation, total U.S. LNG export nameplate capacity stands at 6.1 Bcf/d baseload (6.9 Bcf/d peak) across five LNG export terminals and 10 liquefaction trains. By 2021, EIA projects U.S. LNG export capacity to reach 9.5 Bcf/d baseload (10.8 Bcf/d peak) across six LNG export facilities and 25 liquefaction trains.
Overview:
(For the week ending Wednesday, September 11, 2019)
- Natural gas spot prices rose at most locations this report week (Wednesday, September 4 to Wednesday, September 11). Henry Hub spot prices rose from $2.42 per million British thermal units (MMBtu) last Wednesday to $2.59/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the October 2019 contract increased 11¢, from $2.445/MMBtu last Wednesday to $2.552/MMBtu yesterday. The price of the 12-month strip averaging October 2019 through September 2020 futures contracts climbed 9¢/MMBtu to $2.561/MMBtu
- Net injections to working gas totaled 78 billion cubic feet (Bcf) for the week ending September 6. Working natural gas stocks are 3,019 Bcf, which is 15% more than the year-ago level and 2% lower than the five-year (2014–18) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 30¢/MMBtu, averaging $4.86/MMBtu for the week ending September 11. The price of natural gasoline, ethane, propane, butane, and isobutane all rose, by 6%, 12%, 5%, 3%, and 5%, respectively.
- According to Baker Hughes, for the week ending Tuesday, September 3, the natural gas rig count decreased by 2 to 160. The number of oil-directed rigs fell by 4 to 738. The total rig count decreased by 6, and it now stands at 898.
Prices/Supply/Demand:
Prices rise at most locations. This report week (Wednesday, September 4 to Wednesday, September 11), Henry Hub spot prices rose 17¢ from a weekly low of $2.42/MMBtu last Wednesday to $2.59/MMBtu yesterday. For much of the country, temperatures were generally warmer than normal, but they were slightly cooler than normal in California and across the northern part of the country. At the Chicago Citygate, prices increased 19¢ from $2.18/MMBtu last Wednesday to $2.37/MMBtu yesterday.
California prices are mixed as temperatures cool. Prices at PG&E Citygate in Northern California rose 21¢, up from $3.02/MMBtu last Wednesday to $3.23/MMBtu yesterday. Prices at SoCal Citygate decreased $1.19 from a weekly high of $4.51/MMBtu last Wednesday to $3.32/MMBtu yesterday as last week’s hot temperatures abated.
Northeast prices rise. After relatively low prices last week, prices in New England rose with increased electric power consumption, despite cooler temperatures. At the Algonquin Citygate, which serves Boston-area consumers, prices went up 36¢ from $2.02/MMBtu last Wednesday to $2.38/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 40¢ from $1.90/MMBtu last Wednesday to $2.30/MMBtu yesterday.
Tennessee Zone 4 Marcellus spot prices increased 23¢ from $1.76/MMBtu last Wednesday to $1.99/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 16¢ from $1.84/MMBtu last Wednesday to $2.00/MMBtu yesterday.
Permian Basin prices strengthen throughout the week. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged a weekly low of $0.83/MMBtu last Wednesday, $1.59/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged a weekly high of $1.68/MMBtu, 91¢/MMBtu lower than Henry Hub prices. Permian prices have increased recently as the Gulf Coast Express Pipeline is preparing to enter service within the month.
Supply is flat. According to data from IHS Markit, the average total supply of natural gas remained the same as in the previous report week, averaging 96.5 Bcf/d. Dry natural gas production remained constant week over week. Average net imports from Canada increased by 7% from last week as exports to Canada on the Vector pipeline decreased week-on-week by 30%, dropping from a weekly average of 1.1 Bcf/d to 0.8 Bcf/d.
Demand rises. Total U.S. consumption of natural gas rose by 2% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 3% week over week. Industrial sector consumption stayed constant, averaging 21.5 Bcf/d. In the residential and commercial sectors, consumption also remained at last week's level, averaging 8.9 Bcf/d. Natural gas exports to Mexico decreased 1%.
U.S. LNG exports decrease week over week. Ten LNG vessels (five from Sabine Pass, three from Corpus Christi, and one each from Cove Point and Cameron LNG export terminals) with a combined LNG-carrying capacity of 37 Bcf departed the United States between September 5 and September 11, according to shipping data compiled by Bloomberg. Three vessels (one at each of the Sabine Pass, Freeport, and Cove Point terminals) were loading on Wednesday.
Storage:
Net injections into storage totaled 78 Bcf for the week ending September 6, compared with the five-year (2014–18) average net injections of 73 Bcf and last year's net injections of 68 Bcf during the same week. Working gas stocks totaled 3,019 Bcf, which is 77 Bcf lower than the five-year average and 393 Bcf more than last year at this time.
According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas stocks ranged from net injections of 74 Bcf to 95 Bcf, with a median estimate of 82 Bcf.
The average rate of net injections into storage is 29% 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 10.8 Bcf/d for the remainder of the refill season, total inventories would be 3,615 Bcf on October 31, which is 77 Bcf lower than the five-year average of 3,692 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:
| Spot Prices ($/MMBtu) | Thu, 05-Sep |
Fri, 06-Sep |
Mon, 09-Sep |
Tue, 10-Sep |
Wed, 11-Sep |
|---|---|---|---|---|---|
| Henry Hub |
2.43 |
2.50 |
2.64 |
2.61 |
2.59 |
| New York |
1.84 |
1.83 |
2.12 |
2.38 |
2.30 |
| Chicago |
2.19 |
2.17 |
2.37 |
2.49 |
2.37 |
| Cal. Comp. Avg.* |
2.82 |
2.55 |
2.80 |
2.71 |
2.75 |
| Futures ($/MMBtu) | |||||
| October contract | 2.435 |
2.496 |
2.585 |
2.580 |
2.552 |
| November contract |
2.491 |
2.551 |
2.625 |
2.620 |
2.589 |
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Sources: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. | |||||
| U.S. natural gas supply - Gas Week: (9/5/19 - 9/11/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 103.6 |
103.9 |
94.9 |
| Dry production | 92.0 |
92.3 |
85.0 |
| Net Canada imports | 4.5 |
4.2 |
4.5 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 96.5 |
96.6 |
89.6 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (9/5/19 - 9/11/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 67.8 |
66.7 |
65.2 |
| Power | 37.5 |
36.3 |
35.2 |
| Industrial | 21.5 |
21.4 |
21.9 |
| Residential/commercial | 8.9 |
8.9 |
8.1 |
| Mexico exports | 5.1 |
5.1 |
4.9 |
| Pipeline fuel use/losses | 6.4 |
6.4 |
5.9 |
| LNG pipeline receipts | 5.8 |
6.3 |
3.3 |
| Total demand | 85.1 |
84.4 |
79.3 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, September 03, 2019 |
Change from |
||
last week |
last year |
||
| Oil rigs | 738 |
-0.5% |
-14.2% |
| Natural gas rigs | 160 |
-1.2% |
-14.0% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, September 03, 2019 |
Change from |
||
last week |
last year |
||
| Vertical | 0 |
0.0% |
0.0% |
| Horizontal | 15 |
-6.3% |
-50.0% |
| Directional | 67 |
-4.3% |
3.1% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2019-09-06 |
2019-08-30 |
change |
|
| East | 739 |
714 |
25 |
|
| Midwest | 864 |
827 |
37 |
|
| Mountain | 183 |
177 |
6 |
|
| Pacific | 275 |
276 |
-1 |
|
| South Central | 958 |
947 |
11 |
|
| Total | 3,019 |
2,941 |
78 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (9/6/18) |
5-year average (2014-2018) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 676 |
9.3 |
756 |
-2.2 |
|
| Midwest | 729 |
18.5 |
848 |
1.9 |
|
| Mountain | 165 |
10.9 |
191 |
-4.2 |
|
| Pacific | 249 |
10.4 |
303 |
-9.2 |
|
| South Central | 805 |
19.0 |
997 |
-3.9 |
|
| Total | 2,626 |
15.0 |
3,096 |
-2.5 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Sep 05) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 9 |
-2 |
7 |
14 |
-1 |
-45 |
||
| Middle Atlantic | 2 |
-4 |
2 |
33 |
6 |
-46 |
||
| E N Central | 13 |
2 |
11 |
19 |
-8 |
-55 |
||
| W N Central | 13 |
-3 |
10 |
38 |
1 |
-21 |
||
| South Atlantic | 0 |
-1 |
0 |
92 |
16 |
-15 |
||
| E S Central | 0 |
-1 |
0 |
84 |
15 |
-16 |
||
| W S Central | 0 |
-1 |
0 |
124 |
20 |
6 |
||
| Mountain | 0 |
-20 |
-5 |
92 |
38 |
33 |
||
| Pacific | 0 |
-7 |
-3 |
77 |
40 |
37 |
||
| United States | 5 |
-3 |
3 |
65 |
14 |
-14 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Sep 05, 2019
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Sep 05, 2019
Source: National Oceanic and Atmospheric Administration
