U.S. Energy Information Administration logo

Natural Gas

‹ See the most recent Natural Gas Weekly Update

Natural Gas Weekly Update

for week ending March 20, 2019   |  Release date:  March 21, 2019   |  Next release:  March 28, 2019   |   Previous weeks


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

In the News:

Natural gas consumption in the electric sector reaches highest-ever level in 2018

Natural gas consumption in the electric power sector, or power burn, reached record levels in 2018, growing more than any other end-use sector. Power burn increased by 15% in 2018 relative to 2017 and was nearly 18% higher than the previous five-year (2013—2017) average.

Power burn is partly driven by summer electricity demand for air conditioning, which can be represented by cooling degree days (CDDs). In 2018, the number of CDDs in the Lower 48 states was higher than average, particularly during the summer, which contributed to the year-on-year increase in power burn. However, overall demand in the electric power sector only increased by 4% in 2018, implying that some of the year-on-year increase in power burn can be attributed to higher baseline usage of natural gas.

Most new generation capacity installed in 2018 was natural gas-fired, with Pennsylvania reporting the highest levels of natural gas-fired generation capacity buildout, followed by Virginia and Maryland. These states are part of the Pennsylvania-New Jersey-Maryland (PJM) Interconnection, the largest electric regional transmission organization (RTO) in the United States. In 2018, for the first time in PJM’s history, installed natural gas-fired generation capacity exceeded coal-fired generation capacity, comprising 30.6% and 28.6% of total regional generation capacity, respectively, according to PJM’s recently released State of the Market report. In addition, substantial coal retirements in 2018, most notably in Texas, Ohio, and Florida, increased reliance on natural gas as a generation fuel for those states. All six of these states reached their highest-ever July generation levels in 2018, although unusually hot weather also contributed to this increase.

In addition, increases in natural gas power burn are also the result of favorable natural gas prices, substantial natural gas pipeline buildout, and record-high natural gas production in recent years, which together have made natural gas-fired generators more economically competitive in more regions of the country.

Most newly built natural gas-fired generation capacity uses combined-cycle technology, which is the most efficient type of natural gas-fired generation. Most of the new generation capacity in the coming years is expected to be natural gas combined-cycle plants and solar photovoltaic. EIA’s Short-Term Energy Outlook forecasts that natural gas consumption in the electric power sector will set a new annual record in 2019 and again in 2020.

Overview:

(For the week ending Wednesday, March 20, 2019)

  • Natural gas spot prices rose at most locations this report week (Wednesday, March 13 to Wednesday, March 20). Henry Hub spot prices rose from $2.81 per million British thermal units (MMBtu) last Wednesday to $2.83/MMBtu yesterday.
  • At the New York Mercantile Exchange (Nymex), the price of the April 2019 contract was unchanged Wednesday to Wednesday at $2.82/MMBtu. The price of the 12-month strip averaging April 2019 through March 2020 futures contracts remained the same Wednesday to Wednesday at $2.970/MMBtu.
  • Net withdrawals from working gas totaled 47 billion cubic feet (Bcf) for the week ending March 15. Working natural gas stocks are 1,143 Bcf, which is 22% lower than the year-ago level and 33% lower than the five-year (2014–18) average for this week.
  • According to Baker Hughes, for the week ending Tuesday, March 12, the natural gas rig count remained flat at 193. The number of oil-directed rigs fell by 1 to 833. The total rig count decreased by 1, and it now stands at 1,026.

more summary data

Prices/Supply/Demand:

Prices remain flat or rise slightly across the country. Prices traded within narrow ranges despite a bomb cyclone in the Central United States at the beginning of the report week (Wednesday, March 13 to Wednesday, March 20). During the report week, Henry Hub spot prices rose 2¢ from $2.81/MMBtu last Wednesday to $2.83/MMBtu yesterday. At the Chicago Citygate, prices were unchanged from last Wednesday at $2.69/MMBtu. Prices at PG&E Citygate in Northern California rose 8¢, up from $3.69/MMBtu last Wednesday to $3.77/MMBtu yesterday. Prices at SoCal Citygate increased 1¢ from $4.19/MMBtu last Wednesday to $4.20/MMBtu yesterday.

Northeast prices increase. At the Algonquin Citygate, which serves Boston-area consumers, prices went up 13¢ from $2.83/MMBtu last Wednesday to $2.96/MMBtu yesterday. Similarly, at the Transcontinental Pipeline Zone 6 trading point for New York City, prices also increased 13¢ from $2.62/MMBtu last Wednesday to $2.75/MMBtu yesterday.

Tennessee Zone 4 Marcellus spot prices increased 20¢ from $2.40/MMBtu last Wednesday to $2.60/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 12¢ from $2.48/MMBtu last Wednesday to their weekly high of $2.60/MMBtu yesterday.

Price discount at Permian Basin grows with force majeure. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $1.67/MMBtu last Wednesday, $1.14/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $0.26/MMBtu, $2.57/MMBtu lower than Henry Hub prices.

The El Paso Natural Gas Company issued a force majeure at its Lordsburg and Florida Compressor Stations in southwestern New Mexico. It went into effect on March 18, reducing westbound flows out of the Permian Basin. According to the notice, this event reduced the operational capacity flowing westbound by 0.2 Bcf/d, resulting in an operational capacity of 0.38 Bcf/d on March 19. On that day, prices reached a weekly low of $0.15/MMBtu. The is the lowest price since February, when prices fell to $0.09/MMBtu when another force majeure on the El Paso system limited westbound flows out of the Permian Basin.

Supply is flat. According to data from PointLogic Energy, the average total supply of natural gas remained the same as in the previous report week, averaging 93.5 Bcf/d. Dry natural gas production remained constant week over week. Average net imports from Canada increased by 4% from last week, driven by higher net imports from Canada into the Midwest.

Overall demand decreases, driven by decreased natural gas consumption in the residential and commercial sectors. Total U.S. consumption of natural gas fell by 8% compared with the previous report week, according to data from PointLogic Energy. In the residential and commercial sectors, consumption declined by 17% as a result of warmer–than-normal temperatures in the population centers of California and the Northeast. Natural gas consumed for power generation was flat, averaging 22.5 Bcf/d. Industrial sector consumption decreased by 1% week over week. Natural gas exports to Mexico decreased 2%.

U.S. liquefied natural gas (LNG) exports decrease week over week. Seven LNG vessels (six from Sabine Pass and one from Corpus Christi) with a combined LNG-carrying capacity of 24.8 Bcf departed the United States between March 14 and March 20, according to shipping data compiled by Bloomberg. One vessel was loading at the Sabine Pass terminal on Tuesday. Data for Cove Point LNG exports were unavailable this report week.

Storage:

Net withdrawals from storage totaled 47 Bcf for the week ending March 15, compared with the five-year (2014–18) average net withdrawals of 56 Bcf and last year's net withdrawals of 87 Bcf during the same week. Working gas stocks totaled 1,143 Bcf, which is 556 Bcf lower than the five-year average and 315 Bcf lower 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 withdrawals of 27 Bcf to 56 Bcf, with a median estimate of 48 Bcf.

The average rate of net withdrawals from storage is 3% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 3.9 Bcf/d for the remainder of the withdrawal season, total inventories would be 1,080 Bcf on March 31, which is 556 Bcf lower than the five-year average of 1,636 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 ($/MMBtu)
Thu,
14-Mar
Fri,
15-Mar
Mon,
18-Mar
Tue,
19-Mar
Wed,
20-Mar
Henry Hub
2.87
2.85
2.86
2.91
2.83
New York
2.53
2.80
2.81
2.75
2.75
Chicago
2.74
2.70
2.73
2.75
2.69
Cal. Comp. Avg.*
3.68
3.20
3.06
3.13
3.05
Futures ($/MMBtu)
April contract
2.855
2.795
2.850
2.874
2.820
May contract
2.860
2.802
2.856
2.872
2.825
*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: (3/14/19 - 3/20/19)
Average daily values (Bcf/d):
this week
last week
last year
Marketed production
99.2
99.3
88.6
Dry production
88.3
88.3
78.9
Net Canada imports
5.1
4.9
6.7
LNG pipeline deliveries
0.1
0.1
0.2
Total supply
93.5
93.4
85.7

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: (3/14/19 - 3/20/19)
Average daily values (Bcf/d):
this week
last week
last year
U.S. consumption
74.8
81.0
79.6
    Power
22.5
22.4
23.1
    Industrial
22.0
22.3
22.1
    Residential/commercial
30.3
36.3
34.4
Mexico exports
4.6
4.7
4.4
Pipeline fuel use/losses
6.3
6.5
6.0
LNG pipeline receipts
5.5
5.2
3.1
Total demand
91.3
97.3
93.1

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, March 12, 2019
Change from
 
last week
last year
Oil rigs
833
-0.1%
4.1%
Natural gas rigs
193
0.0%
2.1%
Note: Excludes any miscellaneous rigs
Rig numbers by type
Tue, March 12, 2019
Change from
 
last week
last year
Vertical
54
-3.6%
-5.3%
Horizontal
907
0.3%
4.9%
Directional
65
-3.0%
-4.4%
Source: Baker Hughes Inc.


Working gas in underground storage
Stocks
billion cubic feet (Bcf)
Region
2019-03-15
2019-03-08
change
East
245
262
-17
Midwest
268
287
-19
Mountain
 62
 66
-4
Pacific
 96
102
-6
South Central
471
    473  R
-2
Total
1,143
  1,190  R
-47
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report
R = Revised
Working gas in underground storage
Historical comparisons
Year ago
(3/15/18)
5-year average
(2014-2018)
Region
Stocks (Bcf)
% change
Stocks (Bcf)
% change
East
276
-11.2
310
-21.0
Midwest
320
-16.3
374
-28.3
Mountain
90
-31.1
115
-46.1
Pacific
169
-43.2
200
-52.0
South Central
603
-21.9
699
-32.6
Total
1,458
-21.6
1,699
-32.7
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report


Temperature – heating & cooling degree days (week ending Mar 14)
 
HDD deviation from:
 
CDD deviation from:
Region
HDD Current
normal
last year
CDD Current
normal
last year
New England
228
16
23
0
0
0
Middle Atlantic
201
3
-15
0
0
0
E N Central
190
-18
-17
0
0
0
W N Central
210
2
2
0
-1
0
South Atlantic
100
-18
-44
16
6
10
E S Central
73
-40
-60
3
-1
3
W S Central
35
-34
-18
22
12
14
Mountain
182
18
18
0
-1
0
Pacific
128
36
40
0
-1
0
United States
154
-3
-6
6
2
4
Note: HDD = heating degree day; CDD = cooling degree day

Source: National Oceanic and Atmospheric Administration

Average temperature (°F)

7-day mean ending Mar 14, 2019

Mean Temperature (F) 7-Day Mean ending Mar 14, 2019

Source: National Oceanic and Atmospheric Administration

Deviation between average and normal (°F)

7-day mean ending Mar 14, 2019

Mean Temperature Anomaly (F) 7-Day Mean ending Mar 14, 2019

Source: National Oceanic and Atmospheric Administration