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Natural Gas Weekly Update

for week ending July 17, 2019   |  Release date:  July 18, 2019   |  Next release:  July 25, 2019   |   Previous weeks


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

In the News:

Australia is on track to become the world’s largest LNG exporter in 2019

The June 2019 production and shipment of the first liquefied natural gas (LNG) export cargo from the Prelude Floating LNG (FLNG) barge, located offshore northwestern Australia, signified an important milestone for Australia’s LNG export industry. Prelude FLNG was the last of eight new LNG export projects developed in Australia during the past ten years as part of a massive LNG export capacity buildout that cost an estimated US $200 billion. Between 2012 and 2018, Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) to more than 11.4 Bcf/d, making it the world’s largest, overtaking Qatar’s capacity of 10.1 Bcf/d.

Australia is on track to become world’s largest LNG exporter this year, according to projections by the Australia’s Department of Industry, Innovation and Science (DIIS), once the newly commissioned projects ramp up and operate at full capacity. In November and December 2018, Australia briefly overtook Qatar as the world’s largest LNG exporter, according to DIIS. DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d in 2019–2021, once the recently commissioned Wheatstone, Ichthys, and Prelude projects ramp up to full production.

Starting in 2012, five LNG export projects were developed in northwestern Australia:

  • Pluto (0.6 Bcf/d capacity)
  • Gorgon (three liquefaction units (or trains), combined capacity 2.1 Bcf/d)
  • Wheatstone (two trains, combined capacity 1.2 Bcf/d)
  • Ichthys (two trains, combined capacity 1.2 Bcf/d)
  • Offshore Prelude FLNG (0.5 Bcf/d capacity)

The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In 2015–16, three LNG export projects were completed in eastern Australia on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.3 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane (CBM) as a feedstock to produce LNG.

In the past several years, Australian natural gas markets in the eastern and southeastern states of Queensland, New South Wales, Victoria, South Australia, and Tasmania have been experiencing natural gas shortages and increasing prices. Because CBM production at some LNG export facilities in Queensland was insufficient to meet export commitments, project developers were supplementing their own production with natural gas purchased from the domestic market. In addition, Australian western and eastern natural gas and electricity markets are not interconnected, so natural gas produced in the Northwest cannot be shipped to demand centers in the eastern states, where most of the Australian population lives. During the past few years, the Australian government has implemented several initiatives to address these challenges.

Several private companies proposed to develop LNG import terminals in eastern Australia to mitigate potential natural gas supply shortfall expected in the coming years. Currently, five proposed LNG import projects are in various stages of development. Of these projects, Port Kembla LNG (proposed import capacity of 0.26 Bcf/d) is in the most advanced stage; it has secured the required siting permits and an offtake contract with Australian customers. This project will use a Floating Storage and Regasification Unit (FSRU), Höegh Galleon, starting in January 2021.

Overview:

(For the week ending Wednesday, July 17, 2019)

  • Natural gas spot prices fell at most locations this report week (Wednesday, July 10 to Wednesday, July 17). Henry Hub spot prices fell from $2.46 per million British thermal units (MMBtu) last Wednesday to $2.38/MMBtu yesterday.
  • At the New York Mercantile Exchange (Nymex), the price of the August 2019 contract decreased 14¢, from $2.444/MMBtu last Wednesday to $2.304/MMBtu yesterday. The price of the 12-month strip averaging August 2019 through July 2020 futures contracts declined 11¢/MMBtu to $2.463/MMBtu.
  • Net injections to working gas totaled 62 billion cubic feet (Bcf) for the week ending July 12. Working natural gas stocks are 2,533 Bcf, which is 13% more than the year-ago level and 5% lower than the five-year (2014–18) average for this week.
  • The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 19¢/MMBtu, averaging $4.71/MMBtu for the week ending July 17. The price of ethane, propane, and isobutane rose by 14%, 4%, and 2%, respectively. The price of natural gasoline and butane remained flat week over week.
  • According to Baker Hughes, for the week ending Tuesday, July 9, the natural gas rig count decreased by 2 to 172. The number of oil-directed rigs fell by 4 to 784. The total rig count decreased by 5, and it now stands at 958.

more summary data

Prices/Supply/Demand:

Prices fall at most locations. This report week (Wednesday, July 10 to Wednesday, July 17), Henry Hub spot prices fell 8¢ from $2.46/MMBtu last Wednesday to $2.38/MMBtu yesterday. For most of the report week, temperatures were within normal ranges across most of the country, but they were a bit cooler than normal in the Gulf region in the wake of Hurricane Barry. At the end of the report week, a heat wave began building over population centers on the East Coast and in the Midwest, but thus far it has had a limited effect on prices. At the Chicago Citygate, prices decreased 6¢ from $2.32/MMBtu last Wednesday to $2.26/MMBtu yesterday.

California price movements mixed. Prices at PG&E Citygate in Northern California fell 23¢, down from $2.92/MMBtu last Wednesday to $2.69/MMBtu yesterday. Prices at SoCal Citygate increased 16¢ from $2.53/MMBtu last Wednesday to $2.69/MMBtu yesterday.

Northeast prices trade in narrow ranges. At the Algonquin Citygate, which serves Boston-area consumers, prices went down 9¢ from $2.44/MMBtu last Wednesday to $2.35/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 3¢ from $2.38/MMBtu last Wednesday to $2.41/MMBtu yesterday.

Tennessee Zone 4 Marcellus spot prices decreased 11¢ from $2.21/MMBtu last Wednesday to $2.10/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania fell 6¢ from $2.20/MMBtu last Wednesday to $2.14/MMBtu yesterday.

Permian Basin prices trade in positive territory throughout the week. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged a weekly low of $0.68/MMBtu last Wednesday, $1.78/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $0.78/MMBtu, $1.60/MMBtu lower than Henry Hub prices. Prices reached a high of $1.25/MMBtu on Thursday.

Supply lower as production is taken offline. According to data from PointLogic Energy, the average total supply of natural gas fell by 2% compared with the previous report week. Dry natural gas production decreased by 2% compared with the previous report week as a result of the temporarily shut-in of over half of Gulf of Mexico production through this report week because of Hurricane Barry. Net imports from Canada remained the same as last week, averaging 5.3 Bcf/d.

Demand rises as power generation reaches an all-time record. Total U.S. consumption of natural gas rose by 2% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation climbed by 6% week over week. Consumption reached an all-time high of 43.8 Bcf/d yesterday with the onset of a heat wave, which will likely continue to drive up demand in the coming report week.

Industrial sector consumption decreased by 4% week over week, likely because of a disruption caused by Hurricane Barry in the Gulf region, where much of the country’s industrial facilities are located. In the residential and commercial sectors, consumption increased by 3%. Natural gas exports to Mexico increased 3%.

U.S. LNG exports decrease week over week. Nine LNG vessels (five from Sabine Pass, three from Corpus Christi, and one from Cove Point) with a combined LNG-carrying capacity of 32.9 Bcf departed the United States between July 11 and July 17, according to shipping data compiled by Bloomberg. Three vessels were loading at terminals on Wednesday: two at Sabine Pass terminal and one at Cameron.

Storage:

Net injections into storage totaled 62 Bcf for the week ending July 12, compared with the five-year (2014–18) average net injections of 63 Bcf and last year's net injections of 46 Bcf during the same week. Working gas stocks totaled 2,533 Bcf, which is 143 Bcf lower than the five-year average and 291 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 54 Bcf to 78 Bcf, with a median estimate of 65 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 9.2 Bcf/d for the remainder of the refill season, total inventories would be 3,549 Bcf on October 31, which is 143 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 ($/MMBtu)
Thu,
11-Jul
Fri,
12-Jul
Mon,
15-Jul
Tue,
16-Jul
Wed,
17-Jul
Henry Hub
2.48
2.49
2.46
2.36
2.38
New York
2.36
2.31
2.36
2.35
2.41
Chicago
2.35
2.34
2.32
2.24
2.26
Cal. Comp. Avg.*
2.64
2.56
2.61
2.38
2.41
Futures ($/MMBtu)
August contract
2.416
2.453
2.408
2.306
2.304
September contract
2.401
2.434
2.386
2.286
2.278
*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: (7/11/19 - 7/17/19)
Average daily values (Bcf/d):
this week
last week
last year
Marketed production
99.3
101.5
93.5
Dry production
88.4
90.4
82.9
Net Canada imports
5.3
5.3
6.1
LNG pipeline deliveries
0.1
0.1
0.1
Total supply
93.8
95.7
89.1

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: (7/11/19 - 7/17/19)
Average daily values (Bcf/d):
this week
last week
last year
U.S. consumption
68.7
67.1
69.9
    Power
41.4
39.2
41.8
    Industrial
19.6
20.4
20.8
    Residential/commercial
7.7
7.5
7.3
Mexico exports
5.0
4.8
4.9
Pipeline fuel use/losses
6.1
6.2
5.9
LNG pipeline receipts
5.8
6.1
3.3
Total demand
85.6
84.3
84.0

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 09, 2019
Change from
 
last week
last year
Oil rigs
784
-0.5%
-9.2%
Natural gas rigs
172
-1.1%
-9.0%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, July 09, 2019
Change from
 
last week
last year
Vertical
1
0.0%
0.0%
Horizontal
16
0.0%
-33.3%
Directional
70
6.1%
2.9%
Source: Baker Hughes Inc.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2019-07-12
2019-07-05
change
East
561
544
17
Midwest
627
597
30
Mountain
 147
 140
7
Pacific
268
263
5
South Central
929
927
2
Total
2,533
2,471
62
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report
Working gas in underground storage
Historical comparisons
Year ago
(7/12/18)
5-year average
(2014-2018)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
503
11.5
584
-3.9
Midwest
498
25.9
634
-1.1
Mountain
144
2.1
169
-13.0
Pacific
259
3.5
293
-8.5
South Central
839
10.7
996
-6.7
Total
2,242
13.0
2,676
-5.3
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Jul 11)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
0
-1
-1
58
21
3
Middle Atlantic
0
-1
-1
74
21
9
E N Central
0
-1
-2
76
23
14
W N Central
0
-3
0
71
4
-11
South Atlantic
0
0
0
110
15
16
E S Central
0
0
0
115
24
14
W S Central
0
0
0
133
12
14
Mountain
1
-6
1
72
-3
-25
Pacific
2
-3
1
36
-3
-42
United States
1
-2
0
83
12
0
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-day mean ending Jul 11, 2019

Mean Temperature (F) 7-Day Mean ending Jul 11, 2019

Source: National Oceanic and Atmospheric Administration

Deviation between average and normal (°F)

7-day mean ending Jul 11, 2019

Mean Temperature Anomaly (F) 7-Day Mean ending Jul 11, 2019

Source: National Oceanic and Atmospheric Administration