In the News:
New methanol plants expected to boost industrial natural gas usage in 2019–20
New industrial plants being developed in the United States are boosting natural gas consumption in the industrial sector. Industrial natural gas consumption has grown steadily since 2009 as relatively low natural gas prices have encouraged construction of new industrial plants that use natural gas as a feedstock for chemical production. Methanol plants and ammonia, or urea-based fertilizer plants, are among the most natural gas-intensive industrial end users and require natural gas both as a feedstock and for process heat. In the Short-Term Energy Outlook released on January 15, EIA forecasts that these new projects will help drive growth in industrial natural gas demand through the forecast period, which runs through the end of 2020. EIA forecasts industrial consumption will average 23.2 billion cubic feet per day (Bcf/d) in 2019, or 0.5 Bcf/d (2%) higher than 2018 levels, and 23.4 Bcf/d in 2020.
In 2018, one new methanol plant entered service. OCI N.V. Consolidated Energy Limited, and Natgasoline LLC, the owners and operators of the new plant, announced that their 5,000-metric ton per day—or 1.8 million metric tons per annum—methanol plant in Beaumont, Texas, entered service in June 2018. According to the companies, the plant has consistently been running at higher than nameplate capacity. This new plant is now the largest U.S. methanol production facility, consuming an estimated 0.16 Bcf/d of natural gas.
During 2019–20, two new methanol plants on the Gulf Coast are expected to enter service. Big Lake 1, owned by GX2 Energy and Methanol Holdings, Trinidad, is expected to enter service during the third quarter of 2019 in Louisiana. The Big Lake facility will convert dry natural gas into methanol, which will then be converted to gasoline. Yuhuang’s St. James 1 methanol plant is expected to enter service in mid-2020, and it will be the second-largest methanol facility in the United States after the facility in Beaumont.
In addition to these Gulf Coast methanol plants, Liberty One in West Virginia is expected to begin operations in 2019. Liberty One is a much smaller methanol-producing facility that is relocating from Rio De Janeiro, Brazil, and will have a nameplate capacity of 200,000 metric tons per annum. Liberty One’s proximity to the Appalachia Basin also ensures feedstock natural gas supply at a relatively low cost to the plant.
These three new plants, with in-service dates in 2019–20, have a combined capacity of 3.3 million metric tons per year, equating to methanol production of 0.30 billion British thermal units per day, a 45% increase from the current U.S. capacity.
Overview:
(For the Week Ending Wednesday, January 23, 2019)
- Natural gas spot prices fell at most locations this report week (Wednesday, January 16 to Wednesday, January 23). Henry Hub spot prices fell from $3.61 per million British thermal units (MMBtu) last Wednesday to $3.10/MMBtu yesterday.
- At the Nymex, the price of the February 2019 contract decreased 40¢, from $3.384/MMBtu last Wednesday to $2.98/MMBtu yesterday. The price of the 12-month strip averaging February 2019 through January 2020 futures contracts declined 5¢/MMBtu to $2.917/MMBtu.
- Net withdrawals from working gas totaled 163 billion cubic feet (Bcf) for the week ending January 18. Working natural gas stocks are 2,370 Bcf, which is 1% more than the year-ago level and 11% lower than the five-year (2014–18) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 5¢/MMBtu, averaging $6.51/MMBtu for the week ending January 23. The price of natural gasoline fell by 2%. The price of ethane and butane rose by 2%, and the price of propane rose by 1%. The price of isobutane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, January 15, the natural gas rig count decreased by 4 to 198. The number of oil-directed rigs fell by 21 to 852. The total rig count decreased by 25, and it now stands at 1,050. This is the largest week-over-week decrease in total rig count since February 2016.
Prices/Supply/Demand:
Prices fall across the country as cold weather recedes. This report week (Wednesday, January 16 to Wednesday, January 23), Henry Hub spot prices fell 51¢ from $3.61/MMBtu last Wednesday to $3.10/MMBtu yesterday. At the Chicago Citygate, prices decreased 41¢ from $3.52/MMBtu last Wednesday to $3.11/MMBtu yesterday, with a low of $2.97/MMBtu on Tuesday as weekend cold temperatures in the Northeast and Midwest retreated.
Prices west of the Rockies also decreased as a winter storm that brought snow to the mountains of Southern California moved out of the area. Prices at PG&E Citygate in Northern California fell $1.02, down from $4.62/MMBtu last Wednesday to $3.60/MMBtu yesterday. Prices at SoCal Citygate decreased $1.21 from $5.37/MMBtu last Wednesday to $4.16/MMBtu yesterday, with a low of $4.06/MMBtu on Friday.
Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $2.29/MMBtu last Wednesday, $1.32/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $2.14/MMBtu, 96¢/MMBtu lower than Henry Hub prices. This differential reached a weekly maximum of $1.91/MMBtu on Friday.
Northeast prices are volatile amid several cold weather events. Prices at the Algonquin Citygate, which serves Boston-area consumers, were volatile amid stretches of cold temperatures. Prices went down $7.85 from $11.38/MMBtu last Wednesday to $3.53/MMBtu yesterday. Prices decreased to $9.82 on Thursday, but then increased again to a weekly high of $13.56/MMBtu on Friday because of cold temperatures that were anticipated over the holiday weekend.
For daily updates on New England temperatures and natural gas use, see EIA’s New England Dashboard.
At the Transcontinental Pipeline Zone 6 trading point for New York City, prices decreased $1.06 from $4.04/MMBtu last Wednesday to $2.98/MMBtu yesterday, with a high of $18.79/MMBtu on Friday, also in anticipation of weekend cold. In Rhode Island, 6,800 customers of National Grid had their natural gas services suspended on Monday night as a result of supply constraints and resulting shortages.
Prices in Appalachia fall as temperatures increase and takeaway capacity is restricted. Tennessee Zone 4 Marcellus spot prices decreased 67¢ from $3.43/MMBtu last Wednesday to $2.76/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania fell 70¢ from $3.42/MMBtu last Wednesday to $2.72/MMBtu yesterday. A combination of factors likely affected prices in the region. As in New England and New York City, cold temperatures throughout the Northeast over the long weekend receded, reducing heating demand. In addition, an explosion Monday on the Texas Eastern Transmission (TETCO) line in southeast Ohio reduced flows through the nearby Berne compressor station. Flows past Berne averaged 1.8 Bcf/d in the week before the explosion and fell to less than 0.2 Bcf/d after the event, according to data from PointLogic Energy. TETCO flows natural gas out of Appalachia down to the Gulf Coast and is a major route for moving natural gas out of the Marcellus region.
Supply falls. According to data from PointLogic Energy, the average total supply of natural gas fell by 1% compared with the previous report week. Dry natural gas production decreased by 1% compared with the previous report week. Average net imports from Canada decreased by 6% from last week.
Demand rises amid cold temperatures. Total U.S. consumption of natural gas rose by 4% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation was flat, averaging 25.3 Bcf/d. Industrial sector consumption increased by 1% week over week. In the residential and commercial sectors, consumption increased by 8% as cold temperatures spurred heating demand. Natural gas exports to Mexico increased 1%.
U.S. liquefied natural gas (LNG) exports decrease week over week. Six LNG vessels (four from Sabine Pass, one from Cove Point and one from Corpus Christi) with a combined LNG-carrying capacity of 21.6 Bcf departed the United States between January 17 and January 23. Two vessels were loading at the Sabine Pass terminal on Wednesday, according to shipping data compiled by Bloomberg.
Storage:
Net withdrawals from storage totaled 163 Bcf for the week ending January 18, compared with the five-year (2014–18) average net withdrawals of 185 Bcf and last year's net withdrawals of 273 Bcf during the same week. Working gas stocks totaled 2,370 Bcf, which is 305 Bcf lower than the five-year average and 33 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 withdrawals of 150 Bcf to 169 Bcf, with a median estimate of 157 Bcf.
The average rate of net withdrawals from storage is 28% 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 14.4 Bcf/d for the remainder of the withdrawal season, total inventories would be 1,331 Bcf on March 31, which is 305 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:
| Spot Prices ($/MMBtu) | Thu, 17-Jan |
Fri, 18-Jan |
Mon, 21-Jan |
Tue, 22-Jan |
Wed, 23-Jan |
|---|---|---|---|---|---|
| Henry Hub | 3.52 | 3.36 | Holiday | 3.15 | 3.10 |
| New York | 3.59 | 18.79 | Holiday | 3.07 | 2.98 |
| Chicago | 3.40 | 3.26 | Holiday | 2.97 | 3.11 |
| Cal. Comp. Avg.* | 4.58 | 3.79 | Holiday | 3.75 | 3.73 |
| Futures ($/MMBtu) | |||||
| February Contract | 3.413 | 3.482 | Holiday | 3.040 | 2.980 |
| March Contract | 3.174 | 3.239 | Holiday | 2.972 | 2.922 |
| *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: (1/17/19 - 1/23/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 98.2 |
99.2 |
86.0 |
| Dry production | 87.4 |
88.3 |
76.6 |
| Net Canada imports | 5.7 |
6.0 |
6.4 |
| LNG pipeline deliveries | 0.6 |
0.4 |
0.5 |
| Total supply | 93.7 |
94.8 |
83.6 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (1/17/19 - 1/23/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 101.0 |
97.1 |
94.6 |
| Power | 25.3 |
25.3 |
26.1 |
| Industrial | 25.2 |
24.9 |
24.8 |
| Residential/commercial | 50.5 |
46.9 |
43.7 |
| Mexico exports | 4.8 |
4.8 |
4.4 |
| Pipeline fuel use/losses | 7.9 |
7.6 |
7.4 |
| LNG pipeline receipts | 3.8 |
4.8 |
2.1 |
| Total demand | 117.5 |
114.3 |
108.5 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Tue, January 15, 2019 |
Change from |
||
last week |
last year |
||
| Oil rigs | 852 |
-2.4% |
14.1% |
| Natural gas rigs | 198 |
-2.0% |
4.8% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, January 15, 2019 |
Change from |
||
last week |
last year |
||
| Vertical | 66 |
1.5% |
15.8% |
| Horizontal | 929 |
-2.0% |
15.8% |
| Directional | 55 |
-11.3% |
-28.6% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2019-01-18 |
2019-01-11 |
change |
|
| East | 566 |
620 |
-54 |
|
| Midwest | 673 |
729 |
-56 |
|
| Mountain | 121 |
127 |
-6 |
|
| Pacific | 185 |
196 |
-11 |
|
| South Central | 823 |
861 |
-38 |
|
| Total | 2,370 |
2,533 |
-163 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (1/18/18) |
5-year average (2014-2018) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 563 |
0.5 |
619 |
-8.6 |
|
| Midwest | 646 |
4.2 |
711 |
-5.3 |
|
| Mountain | 147 |
-17.7 |
155 |
-21.9 |
|
| Pacific | 235 |
-21.3 |
253 |
-26.9 |
|
| South Central | 746 |
10.3 |
937 |
-12.2 |
|
| Total | 2,337 |
1.4 |
2,675 |
-11.4 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | |||||
| Temperature – heating & cooling degree days (week ending Jan 17) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 293 |
18 |
58 |
0 |
0 |
0 |
||
| Middle Atlantic | 279 |
16 |
24 |
0 |
0 |
0 |
||
| E N Central | 270 |
-27 |
-46 |
0 |
0 |
0 |
||
| W N Central | 268 |
-50 |
-106 |
0 |
0 |
0 |
||
| South Atlantic | 194 |
11 |
10 |
3 |
-5 |
-1 |
||
| E S Central | 181 |
-10 |
-49 |
0 |
-2 |
0 |
||
| W S Central | 121 |
-20 |
-66 |
0 |
-3 |
0 |
||
| Mountain | 207 |
-27 |
8 |
0 |
0 |
0 |
||
| Pacific | 115 |
-7 |
46 |
0 |
-1 |
0 |
||
| United States | 214 |
-12 |
-14 |
1 |
-1 |
0 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-Day Mean ending Jan 17, 2019
Source: NOAA National Weather Service
Deviation between average and normal (°F)
7-Day Mean ending Jan 17, 2019
Source: NOAA National Weather Service
