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Natural Gas Weekly Update

for week ending July 31, 2019   |  Release date:  August 1, 2019   |  Next release:  August 8, 2019   |   Previous weeks


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

In the News:

Natural gas deliveries to U.S. LNG export facilities set a record in July

Natural gas deliveries to U.S. facilities producing liquefied natural gas (LNG) for export set a monthly record in July 2019, averaging 6.0 billion cubic feet per day (Bcf/d)―7% of the total U.S. dry natural gas production―according to data by OPIS PointLogic Energy. Natural gas demand by U.S. LNG export facilities has been the fastest-growing among all natural gas demand sectors, increasing by 1.4 Bcf/d between December 2018 and July 2019, and is poised to continue to grow as new LNG facilities come online in 2019–20. In comparison, U.S. natural gas exports by pipeline to Mexico increased by 0.2 Bcf/d between 2018 (annual average) and January–July 2019 average as connecting domestic pipelines in Mexico continue to experience delays. Combined, natural gas demand for LNG exports and pipeline exports to Mexico reached 10.9 Bcf/d in July, 12% of the total U.S. dry natural gas production.

In the first half of this year, two new liquefaction trains came online—Cameron LNG Train 1 in May and Corpus Christi LNG Train 2 in June. Last week, Cameron LNG Train 1 was approved by the Federal Energy Regulatory Commission to begin commercial operations, after shipping four LNG cargoes from May to July. Corpus Christi Train 2 loaded its first cargo in early July and has been ramping up LNG production. Natural gas feedstock deliveries to Corpus Christi Trains 1 and 2 averaged 1.3 Bcf/d in July compared to 0.9 Bcf/d in the previous month, indicating that Train 2 has ramped up close to full production. EIA estimates that 10 LNG cargoes were loaded at Corpus Christi in July. Total U.S. LNG export capacity currently stands at 5.4 Bcf/d (baseload) across four facilities and nine liquefaction trains.

Two new LNG export facilities—Elba Island LNG in Georgia and Freeport LNG in Texas—are expected to place their first trains in service in the next two months. During the last three weeks, both facilities have begun to receive natural gas feedstock deliveries in preparation for LNG production.

LNG production at Elba Island was expected to begin in May 2019; however, the facility has experienced equipment problems. Kinder Morgan, the developer of Elba Island LNG, stated in a recent conference call that 4 of the 10 Moveable Modular Liquefaction System (MMLS) units are complete and the cold box on the first MMLS unit is uniformly cold. The delay in production at Elba Island was primarily because of the unevenness in cryogenic temperatures between the bottom and the top of the cold box of the MMLS units.

The first train at Freeport LNG is scheduled to come online in September 2019, with the remaining two trains expected to enter service in the second and third quarters of 2020. The remaining trains at Elba Island, Corpus Christi, and Cameron are expected to complete construction and come online in 2020–21.

EIA estimates that U.S. LNG exports set new records in June and July 2019 at 4.8 Bcf/d and 5.2 Bcf/d, respectively. Natural gas feedstock deliveries to LNG export terminals averaged 5.5 Bcf/d in June and 6.0 Bcf/d in July, implying a 14% and a 15%, respectively, loss on conversion of gaseous natural gas into liquefied natural gas (i.e., 14% and 15% of natural gas feedstock was used as fuel in the liquefaction process).

Overview:

(For the week ending Wednesday, July 31, 2019)

  • Natural gas spot price movements were mixed this report week (Wednesday, July 24 to Wednesday, July 31). Henry Hub spot prices rose slightly from $2.22 per million British thermal units (MMBtu) last Wednesday to $2.23/MMBtu yesterday.
  • At the New York Mercantile Exchange (Nymex), the August 2019 contract expired Monday at $2.141/MMBtu, down 8¢/MMBtu from last Wednesday. The September 2019 contract increased to $2.233/MMBtu, up 3¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip, averaging the September 2019 through August 2020 futures contracts, climbed 1¢/MMBtu to $2.424/MMBtu.
  • Net injections to working gas totaled 65 billion cubic feet (Bcf) for the week ending July 26. Working natural gas stocks are 2,634 Bcf, which is 15% more than the year-ago level and 4% lower than the five-year (2014–18) average for this week.
  • The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 49¢/MMBtu, averaging $4.04/MMBtu for the week ending July 31. The price of ethane, propane, butane, and natural gasoline fell by 32%, 11%, 7%, and 1%, respectively. The price of isobutane rose by 2%.
  • According to Baker Hughes, for the week ending Tuesday, July 23, the natural gas rig count decreased by 5 to 169. The number of oil-directed rigs fell by 3 to 776. The total rig count decreased by 8, and it now stands at 946.

more summary data

Prices/Supply/Demand:

Prices across the country trade in narrow ranges. This report week (Wednesday, July 24 to Wednesday, July 31), Henry Hub spot prices traded within a narrow range and rose 1¢ from $2.22/MMBtu last Wednesday to $2.23/MMBtu yesterday. Temperatures across the Lower 48 states were generally close to normal, with pockets of above-normal temperatures in the Northeast and Southwest. At the Chicago Citygate, prices increased 7¢ from $2.01/MMBtu last Wednesday to a high of $2.08/MMBtu yesterday.

California prices decline over the week Prices at PG&E Citygate in Northern California fell 5¢, down from a high of $2.78/MMBtu last Wednesday to $2.73/MMBtu yesterday. Prices at SoCal Citygate decreased 63¢ from a high of $3.58/MMBtu last Wednesday to a low of $2.95/MMBtu yesterday. Warmer-than-normal temperatures in Southern California placed upward pressure on prices and resulted in net withdrawals from storage, according to EIA’s Southern California Daily Energy Report.

Northeast prices rise. At the Algonquin Citygate, which serves Boston-area consumers, prices went up 15¢ from a low of $2.07/MMBtu last Wednesday to $2.22/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 7¢ from $2.09/MMBtu last Wednesday to a high of $2.16/MMBtu yesterday. Price increases in New England were driven by high demand in the electric power sector amid warmer-than-normal temperatures.

Tennessee Zone 4 Marcellus spot prices decreased 6¢ from $1.92/MMBtu last Wednesday to $1.86/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania fell 1¢ from $1.95/MMBtu last Wednesday to $1.94/MMBtu yesterday.

Texas Eastern Transmission pipeline declares force majeure following explosion in Kentucky. On August 1, Spectra Energy’s Texas Eastern Transmission, LP (TETCO) declared a force majeure in Danville, Kentucky following an explosion. The explosion is under investigation with no timeline for a return to service. In the week before the event, southbound flows through Danville averaged 1.7 Bcf/d, according to Genscape, with most of those volumes delivered to Gulf Coast demand markets.

Permian basin area prices are volatile. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $0.86/MMBtu last Wednesday, $1.36/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $0.21/MMBtu, $2.02/MMBtu lower than Henry Hub prices. Prices throughout the week traded within a range of nearly a dollar, reaching a high of $1.04/MMBtu on Thursday and a low of $0.07/MMBtu on Tuesday. An ongoing force majeure on the El Paso Natural Gas pipeline system at the Amarillo compressor station in northern Texas through August 5 has been constraining northbound takeaway capacity, potentially impacting 600 million cubic feet per day (MMcf/d), according to Genscape estimates.

Supply rises as dry production grows. According to data from PointLogic Energy, the average total supply of natural gas rose by 1% compared with the previous report week. Dry natural gas production grew by 1% compared with the previous report week. Average net imports from Canada decreased by 1% from last week.

Demand rises. Total U.S. consumption of natural gas rose by 1% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation declined by 1% week over week. Industrial sector consumption increased by 4% week over week. In the residential and commercial sectors, consumption increased by 1%. Natural gas exports to Mexico increased 1%.

U.S. LNG exports increase week over week. Eleven LNG vessels (six from Sabine Pass, two from Cove Point, and three from Corpus Christi) with a combined LNG-carrying capacity of 39 Bcf departed the United States between July 25 and July 31, according to shipping data compiled by Bloomberg. One vessel was loading at the Sabine Pass terminal on Wednesday.

In July, U.S. LNG exports set another record, with 46 exported cargoes (28 from Sabine Pass, 6 from Cove Point, 10 from Corpus Christi, and 2 from Cameron) carrying an estimated 160 billion cubic feet of natural gas (Bcf), or 5.2 billion cubic feet per day (Bcf/d).

Commissioning of the first LNG trains at Elba Island is ongoing. On Wednesday, Kinder Morgan and Southern LNG Company, the developers of the Elba Island liquefaction facility, filed a request with the Federal Energy Regulatory Commission (FERC) to introduce hazardous fluids to Train 2. Elba Island is a 10-train facility with a combined LNG export capacity of 0.33 Bcf/d for Trains 1–10.

Gulf LNG became the newest U.S. LNG export project to receive full government approval from FERC and the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as non-FTA countries. Gulf LNG plans to build two liquefaction trains, each with a nameplate capacity of 0.66 Bcf/d, to be located at the site of an existing Gulf LNG import terminal (currently not in use) near Pascagoula, Mississippi.

Cameron LNG received an approval by FERC to begin commercial operations. Since the start of LNG production, the facility has shipped four commissioning cargoes between May and July 2019.

Storage:

Net injections into storage totaled 65 Bcf for the week ending July 26, compared with the five-year (2014–18) average net injections of 37 Bcf and last year's net injections of 31 Bcf during the same week. Working gas stocks totaled 2,634 Bcf, which is 123 Bcf lower than the five-year average and 334 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 50 Bcf to 67 Bcf, with a median estimate of 56 Bcf.

The average rate of net injections into storage is 34% 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 9.6 Bcf/d for the remainder of the refill season, total inventories would be 3,569 Bcf on October 31, which is 123 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:



Natural gas spot prices
Spot Prices ($/MMBtu)
Thu,
25-Jul
Fri,
26-Jul
Mon,
29-Jul
Tue,
30-Jul
Wed,
31-Jul
Henry Hub 2.22 2.18 2.17 2.17 2.23
New York 2.05 2.06 2.12 2.12 2.16
Chicago 2.06 2.00 2.02 2.06 2.08
Cal. Comp. Avg.* 2.80 2.53 2.62 2.58 2.59
Futures ($/MMBtu)
August Contract 2.244 2.169 2.141 Expired Expired
September Contract 2.227 2.150 2.116 2.137 2.233
October Contract 2.253 2.177 2.139 2.160 2.250
*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.
Natural gas futures prices
Natural gas liquids spot prices


U.S. natural gas supply - Gas Week: (7/25/19 - 7/31/19)
Average daily values (Bcf/d):
this week
last week
last year
Marketed production
101.2
100.1
92.8
Dry production
90.5
89.5
82.3
Net Canada imports
5.0
5.1
5.6
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
95.6
94.7
88.0

Source: OPIS PointLogic Energy, an IHS Company
Note: LNG pipeline deliveries represent natural gas sendout from LNG import terminals.

U.S. natural gas consumption - Gas Week: (7/25/19 - 7/31/19)
Average daily values (Bcf/d):
this week
last week
last year
U.S. consumption
69.1
68.5
69.6
    Power
40.3
40.5
39.6
    Industrial
21.3
20.4
21.6
    Residential/commercial
7.6
7.6
8.4
Mexico exports
5.0
4.9
4.8
Pipeline fuel use/losses
6.3
6.2
5.9
LNG pipeline receipts
6.0
6.1
3.3
Total demand
86.4
85.7
83.7

Source: OPIS PointLogic Energy, an IHS Company
Note: LNG pipeline receipts represent pipeline deliveries to LNG export terminals.

Natural gas supply


Weekly natural gas rig count and average Henry Hub
Rigs
Tue, July 23, 2019
Change from
 
last week
last year
Oil rigs
776
-0.4%
-9.9%
Natural gas rigs
169
-2.9%
-9.1%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, July 23, 2019
Change from
 
last week
last year
Vertical
56
0.0%
-9.7%
Horizontal
823
-0.7%
-10.7%
Directional
67
-2.9%
4.7%
Source: Baker Hughes Inc.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2019-07-26
2019-07-19
change
East
597
575
22
Midwest
677
650
27
Mountain
 156
 151
5
Pacific
270
271
-1
South Central
934
921
13
Total
2,634
2,569
65
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report
Working gas in underground storage
Historical comparisons
Year ago
(7/26/18)
5-year average
(2014-2018)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
548
8.9
625
-4.5
Midwest
548
23.5
677
0.0
Mountain
146
6.8
174
-10.3
Pacific
250
8.0
294
-8.2
South Central
809
15.5
987
-5.4
Total
2,300
14.5
2,757
-4.5
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Jul 25)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
1
-2
-1
65
20
17
Middle Atlantic
1
-2
0
84
25
25
E N Central
3
0
2
69
11
20
W N Central
2
-1
1
67
-5
3
South Atlantic
0
0
0
105
7
14
E S Central
1
1
1
86
-9
-3
W S Central
0
0
0
117
-9
-37
Mountain
1
-3
1
93
13
-14
Pacific
1
-3
0
62
17
-18
United States
1
-1
1
84
9
2
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-day mean ending Jul 25, 2019

Mean Temperature (F) 7-Day Mean ending Jul 25, 2019

Source: National Oceanic and Atmospheric Administration

Deviation between average and normal (°F)

7-day mean ending Jul 25, 2019

Mean Temperature Anomaly (F) 7-Day Mean ending Jul 25, 2019

Source: National Oceanic and Atmospheric Administration