In the News:
Myanmar becomes the newest country to begin LNG imports
In June 2020, Myanmar became the newest country to begin imports of liquefied natural gas (LNG). A small-scale (0.6 billion cubic feet (Bcf)) LNG vessel delivered an LNG cargo sourced from Malaysia to Thilawa in southeastern Myanmar—an industrial port located outside of Yangon—on June 6, according to shipping data provided by Marine Traffic. A second cargo from Malaysia is currently en route to Myanmar.
Myanmar’s first LNG import facility is located on the Yangon River close to the former capital city of the same name. Although Yangon was replaced as the capital in 2006, it remains the largest city in Myanmar and its most important commercial center. LNG import facility includes an offshore LNG storage vessel (called a Floating Storage Unit (FSU)) to store imported LNG, which, once transferred onshore and regasified, will supply natural gas-fired electric power plants. Because of the shallow depth on the Yangon River, only small-scale LNG vessels can move along the river when laden with LNG. Currently, vessels can use a temporary jetty at Thilawa port designed for small-scale LNG vessels. A permanent jetty is expected to be in service in July 2020 and will accommodate regular-size FSU vessel with a capacity of 2.8 Bcf. A second FSU will be located at the mouth of the Yangon River, and a small-scale LNG vessel will shuttle LNG between the two FSUs.
Electricity in Myanmar is produced primarily by hydroelectric power plants. Hydroelectricity is supplemented by single-cycle low-efficiency natural gas-fired power plants that operate mostly during the dry season (November–May). In recent years, because of the rapid growth in electricity demand and variability in hydroelectric output, Myanmar has been experiencing significant power shortages. Integrated natural gas-fired electric power plants, supplied exclusively with regasified LNG, were considered as the fastest solution to increase electricity generation.
LNG imported at Yangon will supply integrated LNG-to-power projects located near the regasification facilities: Thaketa (400 megawatt (MW) capacity), Thanlyin (350 MW capacity), and Thilawa (1,250 MW capacity). The Thaketa and Thanlyin plants are expected to enter service this summer. The Thilawa natural gas-fired power plant is in the planning stage and is expected to come online by 2024. If the three plants run at a 45%–55% annual capacity factor, they will require between 160 million cubic feet per day (MMcf/d) and 200 MMcf/d of natural gas supply, an equivalent of 21 to 26 LNG cargoes per year (assuming LNG vessels of 2.8 Bcf capacity), averaging about two cargoes per month.
Several other LNG import facilities and accompanying gas-fired power plants are currently being developed in Myanmar. Development of these projects may be delayed because of impacts of COVID-19.
- In the southwest:
- Rakhine LNG import facility is currently under construction. It will supply the Kyaukpyu natural gas-fired power plant (150 MW capacity), which is expected to come online by the end of 2020.
- Mee Laung Gyaing LNG import terminal and LNG-to-power plant (1,390 MW capacity) are proposed in the Ayeyawady region. The project will utilize a Floating Storage and Regasification Unit (FSRU) and is expected to come online by 2024.
- Kanbauk FSRU and associated power plant (1,230 MW capacity) are in the development stage and are expected to come online by 2024.
Overview:
(For the week ending Wednesday, June 17, 2020)
- Natural gas spot prices fell at most locations this report week (Wednesday, June 10, to Wednesday, June 17). The Henry Hub spot price fell from $1.70 per million British thermal units (MMBtu) last Wednesday to $1.48/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the July 2020 contract decreased 14¢, from $1.780/MMBtu last Wednesday to $1.638/MMBtu yesterday. The price of the 12-month strip averaging July 2020 through June 2021 futures contracts declined 7¢/MMBtu to $2.361/MMBtu.
- The net injections to working gas totaled 85 billion cubic feet (Bcf) for the week ending June 12. Working natural gas stocks totaled 2,892 Bcf, which is 33% more than the year-ago level and 17% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 18¢/MMBtu, averaging $4.42/MMBtu for the week ending June 17. The prices of natural gasoline, ethane, butane, and propane, fell by 16%, 4%, 3%, and 2%, respectively. The price of isobutane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, June 9, the natural gas rig count increased by 2 rigs to 78 rigs. The number of oil-directed rigs fell by 7 rigs to 199 rigs. The total rig count decreased by 5 rigs, and it now stands at 279 rigs.
Prices/Supply/Demand:
Henry Hub prices reach 21-year lows, and prices at most trading hubs fall. This report week (Wednesday, June 10, to Wednesday, June 17), the Henry Hub spot price fell 22¢ from a high of $1.70/MMBtu last Wednesday to $1.48/MMBtu yesterday. Henry Hub reached a low of $1.38/MMBtu on Tuesday, the lowest price since December 1998 in nominal terms, according to Natural Gas Intelligence, because of weakened demand from mild U.S. temperatures and low demand for global liquefied natural gas (LNG). Temperatures were cooler than normal on both coasts and generally warmer than normal across the Rocky Mountain region and the Upper Midwest. At the Chicago Citygate, the price decreased 10¢ from a high of $1.61/MMBtu last Wednesday to $1.51/MMBtu yesterday.
California prices are down. The price at SoCal Citygate in Southern California decreased 51¢ from a high of $2.23/MMBtu last Wednesday to $1.72/MMBtu yesterday. The price at PG&E Citygate in Northern California fell 27¢, down from a high of $2.55/MMBtu last Wednesday to a low of $2.28/MMBtu yesterday.
Northeast prices fall. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 14¢ from a high of $1.65/MMBtu last Wednesday to $1.51/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 14¢ from a high of $1.58/MMBtu last Wednesday to $1.44/MMBtu yesterday.
The Tennessee Zone 4 Marcellus spot price decreased 14¢ from $1.44/MMBtu last Wednesday to $1.30/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell 16¢ from $1.47/MMBtu last Wednesday to $1.31/MMBtu yesterday.
Permian Basin discount to the Henry Hub narrows. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $1.40/MMBtu last Wednesday, 30¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $1.27/MMBtu, 21¢/MMBtu lower than the Henry Hub price as Henry Hub reached historic lows. Waha Hub’s narrowing discount to Henry Hub comes with reports from trade press of an increase in associated gas volumes from the Permian Basin.
Supply rises slightly, with gains in dry natural gas production. According to data from IHS Markit, the average total supply of natural gas rose by 0.2% compared with the previous report week as activity in the Gulf of Mexico resumes following Tropical Storm Cristobal, which caused production shut-ins through late last week. Dry natural gas production grew by 0.5% compared with the previous report week. Average net imports from Canada decreased by 5.5% from last week.
Demand falls because of lower power generation. Total U.S. consumption of natural gas fell by 7.1% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 15.6% week over week as mild temperatures limited demand for electric power. In the residential and commercial sectors, consumption increased by 4.8% because of mixed heating and cooling demand. Industrial sector consumption increased by 2.2% week over week. Natural gas exports to Mexico decreased 4.7%.
U.S. LNG exports increase week over week. Eight liquefied natural gas (LNG) vessels (three from Cameron, two from Cove Point, and one each from Sabine Pass, Corpus Christi, and Freeport) with a combined LNG-carrying capacity of 29 billion cubic feet departed the United States between June 11 and June 17, 2020, according to shipping data provided by Marine Traffic.
Storage:
The net injections into storage totaled 85 Bcf for the week ending June 12, compared with the five-year (2015–19) average net injections of 87 Bcf and last year's net injections of 111 Bcf during the same week. Working natural gas stocks totaled 2,892 Bcf, which is 419 Bcf more than the five-year average and 722 Bcf more than last year at this time
According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net injections of 76 Bcf to 89 Bcf, with a median estimate of 84 Bcf.
The average rate of injections into storage is 14% 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 8.9 Bcf/d for the remainder of the refill season, the total inventory would be 4,142 Bcf on October 31, which is 419 Bcf higher than the five-year average of 3,723 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, 11-Jun |
Fri, 12-Jun |
Mon, 15-Jun |
Tue, 16-Jun |
Wed, 17-Jun |
|---|---|---|---|---|---|
| Henry Hub |
1.68 |
1.61 |
1.46 |
1.38 |
1.48 |
| New York |
1.49 |
1.28 |
1.23 |
1.34 |
1.44 |
| Chicago |
1.57 |
1.49 |
1.45 |
1.38 |
1.51 |
| Cal. Comp. Avg.* |
1.91 |
1.81 |
1.81 |
1.69 |
1.72 |
| Futures ($/MMBtu) | |||||
| July contract | 1.813 |
1.731 |
1.669 |
1.614 |
1.638 |
| August contract |
1.900 |
1.815 |
1.760 |
1.701 |
1.727 |
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Source: NGI's Daily Gas Price Index | |||||
| U.S. natural gas supply - Gas Week: (6/11/20 - 6/17/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 101.6 |
100.9 |
102.5 |
| Dry production | 90.0 |
89.5 |
90.6 |
| Net Canada imports | 3.8 |
4.1 |
4.6 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 93.9 |
93.7 |
95.4 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (6/11/20 - 6/17/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 59.8 |
64.4 |
61.1 |
| Power | 29.7 |
35.1 |
31.2 |
| Industrial | 20.9 |
20.4 |
20.5 |
| Residential/commercial | 9.3 |
8.8 |
9.3 |
| Mexico exports | 5.2 |
5.4 |
5.3 |
| Pipeline fuel use/losses | 5.4 |
5.4 |
6.1 |
| LNG pipeline receipts | 3.9 |
4.1 |
5.4 |
| Total demand | 74.2 |
79.3 |
77.9 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, June 09, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 199 |
-3.4% |
-74.7% |
| Natural gas rigs | 78 |
2.6% |
-56.9% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, June 09, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 11 |
57.1% |
-77.6% |
| Horizontal | 246 |
-2.8% |
-71.1% |
| Directional | 22 |
-8.3% |
-67.6% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-06-12 |
2020-06-05 |
change |
|
| East | 586 |
563 |
23 |
|
| Midwest | 688 |
662 |
26 |
|
| Mountain | 156 |
148 |
8 |
|
| Pacific | 290 |
281 |
9 |
|
| South Central | 1,173 |
1,153 |
20 |
|
| Total | 2,892 |
2,807 |
85 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (6/12/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 463 |
26.6 |
490 |
19.6 |
|
| Midwest | 493 |
39.6 |
545 |
26.2 |
|
| Mountain | 116 |
34.5 |
152 |
2.6 |
|
| Pacific | 232 |
25.0 |
279 |
3.9 |
|
| South Central | 866 |
35.5 |
1,008 |
16.4 |
|
| Total | 2,170 |
33.3 |
2,473 |
16.9 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jun 11) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 9 |
-12 |
-2 |
21 |
13 |
11 |
||
| Middle Atlantic | 2 |
-13 |
-5 |
44 |
25 |
27 |
||
| E N Central | 3 |
-15 |
-7 |
52 |
24 |
32 |
||
| W N Central | 5 |
-11 |
-9 |
63 |
27 |
27 |
||
| South Atlantic | 0 |
-4 |
-1 |
93 |
27 |
16 |
||
| E S Central | 0 |
-3 |
-3 |
88 |
28 |
25 |
||
| W S Central | 0 |
0 |
-1 |
110 |
19 |
20 |
||
| Mountain | 28 |
-1 |
2 |
37 |
-7 |
-11 |
||
| Pacific | 19 |
-1 |
12 |
16 |
-2 |
-24 |
||
| United States | 7 |
-8 |
-1 |
60 |
18 |
14 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Jun 11, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Jun 11, 2020
Source: National Oceanic and Atmospheric Administration
