In the News:
Natural gas surpasses coal as primary generation fuel in MISO
Since March 20, 2020, EIA’s Hourly Electric Grid Monitor has shown that natural gas-fired generation has surpassed coal-fired generation as the primary source of electricity dispatched by the Midcontinent Independent System Operator (MISO), the regional transmission organization responsible for managing wholesale electricity generation and transmission across all or parts of 15 central U.S. states and the Canadian province of Manitoba. This is mainly a result of low natural gas prices; the start-up of three major high-efficiency, natural gas-fired combined-cycle power plants since mid-2019; and the increased share of wind-powered generation.
Since March 20, natural gas-fired generation provided approximately 32% of electricity within MISO, whereas coal-fired generation provided about 25% of the region’s electricity. In the three months preceding March 20, natural gas- and coal-fired generation were at parity, each providing approximately 31% of total generation in MISO. Before late December 2019, coal-fired generation almost always provided the greatest share of electricity within MISO.
Relatively low prices have driven the increased use of natural gas for power generation. Since March 20, the spot price of natural gas at the benchmark Henry Hub has averaged $1.70 per million British thermal units (MMBtu), according to Natural Gas Intelligence. However, much of MISO covers the Midwestern states (though not the Chicago area), so the price seen by generators in these states may be closer to the Midwest regional average price, which has been lower than the Henry Hub, averaging $1.60/MMBtu during this period. From December 20, 2019, through March 19, 2020, the Henry Hub price averaged $1.92/MMBtu, and the Midwest regional average averaged $1.79/MMBtu.
Since mid-2019, 2.3 gigawatts (GW) of new high-efficiency, natural gas-fired combined-cycle capacity has opened in MISO. These plants, including the brand new Lake Charles Power Station (a 1.0 GW natural gas combined-cycle plant in Louisiana) that opened on March 28, have very low heat rates, allowing them to be dispatched first and run at high levels.
The capacity of electricity generated by natural gas is expected to continue increasing in MISO, while coal-fired capacity is expected to fall. Through 2022, another 4.3 GW of net natural gas-fired generation capacity is planned to begin operation while 5.1 GW of net coal-fired generation capacity is scheduled to retire in MISO, according to the February 2020 EIA-860M data.
Additionally, wind-powered generation has also increased in MISO, evidenced by the addition of 3.2 GW of new wind turbine capacity since the beginning of 2019, including 660 MW of capacity added in 2020. Increased wind turbine capacity can affect natural gas-powered generation, since natural gas-fired power plants are often used in conjunction with wind power to serve as back-up power.
Overview:
(For the week ending Wednesday, May 13, 2020)
- Natural gas spot prices fell at most locations this report week (Wednesday, May 6 to Wednesday, May 13). The Henry Hub spot price fell from $1.88 per million British thermal units (MMBtu) last Wednesday to $1.56/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the June 2020 contract decreased 33¢, from $1.944/MMBtu last Wednesday to $1.616/MMBtu yesterday. The price of the 12-month strip averaging June 2020 through May 2021 futures contracts declined 20¢/MMBtu to $2.362/MMBtu.
- The net injections into storage totaled 103 Bcf for the week ending May 8, compared with the five-year (2015–19) average net injections of 85 Bcf and last year's net injections of 100 Bcf during the same week. Working natural gas stocks totaled 2,422 Bcf, which is 413 Bcf more than the five-year average and 799 Bcf more than last year at this time.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 40¢/MMBtu, averaging $3.75/MMBtu for the week ending May 13. The prices of ethane, propane, natural gasoline, and butane all rose, by 7%, 10%, 16%, and 18%, respectively. Rapid increase in demand for isobutane for alkylate production (a blendstock for premium gasoline) resulted in isobutane prices rising 29% week over week.
- According to Baker Hughes, for the week ending Tuesday, May 5, the natural gas rig count decreased by 1 to 80. The number of oil-directed rigs fell by 33 to 292. The total rig count decreased by 34, and it now stands at 374.
Prices/Supply/Demand:
Prices decline throughout the week across the Lower 48 states. This report week (Wednesday, May 6 to Wednesday, May 13), the average Henry Hub spot price fell 32¢ from a high of $1.88/MMBtu last Wednesday to a low of $1.56/MMBtu yesterday, the lowest spot price since early April. Prices have experienced downward pressure because of seasonally moderate weather and general economic contraction because of COVID-19 mitigation efforts. According to Natural Gas Intelligence, liquefied natural gas (LNG) feed gas volumes also fell 15% compared to last week, weakening natural gas demand and placing further downward pressure in Gulf Coast markets. So far this May, the average Henry Hub spot price is approximately 32% lower than year-ago levels. Temperatures were unseasonably cool east of the Rocky Mountains and warmer-than-normal in the Western United States. At the Chicago Citygate, the price decreased 37¢ from a high of $1.91/MMBtu last Wednesday to a low of $1.54/MMBtu yesterday.
Natural gas flows out of the Appalachia producing region are still restricted following TETCO explosion. On May 4, Enbridge Inc. reported an explosion on Line 10 of its 30-inch pipeline segment of its Texas Eastern Transmission (TETCO) system near the Owingsville Compressor Station, 50 miles east of Lexington, Kentucky. Before the explosion, TETCO sent an average of 1.3 billion cubic feet per day (Bcf/d) of natural gas from the Appalachia producing region to Gulf Coast demand markets. Although several restrictions are still in place for a minimum of two to three more weeks, supplies within the Appalachia region have been re-routed, increasing 0.9 Bcf/d over the past week, according to data from Genscape.
California prices are down amid seasonal temperatures. The price at PG&E Citygate in Northern California fell 36¢, down from a high of $2.86/MMBtu last Wednesday to a low of $2.50/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased 62¢ from a high of $2.32/MMBtu last Wednesday to a low of $1.70/MMBtu yesterday. There were relatively high net injections into storage, with Southern California Gas inventories 10 Bcf higher than this time last year and the highest they have been for this time of year since 2016, according to Natural Gas Intelligence.
Northeast prices are down despite colder-than-normal temperatures and increased heating demand. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 17¢ from $1.43/MMBtu last Wednesday to a low of $1.26/MMBtu yesterday. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 37¢ from a high of $1.60/MMBtu last Wednesday to a low of $1.23/MMBtu yesterday, even as the region set a new weekly high for natural gas consumption as a result of cold temperatures.
The Tennessee Zone 4 Marcellus spot price decreased 19¢ from $1.26/MMBtu last Wednesday to $1.07/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell 22¢ from $1.40/MMBtu last Wednesday to $1.18/MMBtu yesterday. The outage on the TETCO system, which continues to restrict flows out of the region, put downward pressure on prices in the Appalachia producing region.
Permian Basin differential to the Henry Hub widens. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged a high of $1.77/MMBtu last Wednesday, 11¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged a low of $1.38/MMBtu, 18¢/MMBtu lower than the Henry Hub price. Natural Gas Intelligence notes that higher prices in the Permian recently have coincided with elevated associated gas flows in the region compared with the last two and a half weeks.
Supply rises. According to data from IHS Markit, the average total supply of natural gas rose by 0.8% compared with the previous report week. Dry natural gas production grew by 0.2% compared with the previous report week. Average net imports from Canada increased by 17.3% from last week.
Demand rises because of heating demand in buildings. Total U.S. consumption of natural gas rose by 9.3% compared with the previous report week, according to data from IHS Markit. In the residential and commercial sectors, consumption increased by 34.1%. Cooler-than-normal temperatures across most of the Lower 48 states bolstered heating demand, which is typically low for this time of year. Industrial sector consumption increased by 3.0% week over week. Natural gas exports to Mexico increased 3.8%. Natural gas consumed for power generation declined by 1.2% week over week.
U.S. LNG exports decrease week over week. Eleven liquefied natural gas (LNG) vessels (five from Sabine Pass, three from Freeport, and one from each Cameron, Corpus Christi, and Cove Point) with a combined LNG-carrying capacity of 40 Bcf departed the United States between May 7 and May 13, according to shipping data provided by Marine Traffic.
Storage:
The net injections to working gas totaled 103 billion cubic feet (Bcf) for the week ending May 8. Working natural gas stocks totaled 2,422 Bcf, which is 49% more than the year-ago level and 21% more than the five-year (2015–19) average for this week.
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 93 Bcf to 115 Bcf, with a median estimate of 106 Bcf.
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, 07-May |
Fri, 08-May |
Mon, 11-May |
Tue, 12-May |
Wed, 13-May |
|---|---|---|---|---|---|
| Henry Hub |
1.83 |
1.74 |
1.70 |
1.62 |
1.56 |
| New York |
1.60 |
1.38 |
1.46 |
1.40 |
1.26 |
| Chicago |
1.87 |
1.69 |
1.75 |
1.64 |
1.54 |
| Cal. Comp. Avg.* |
2.07 |
1.96 |
1.98 |
1.93 |
1.83 |
| Futures ($/MMBtu) | |||||
| June contract | 1.894 |
1.823 |
1.826 |
1.720 |
1.616 |
| July contract |
2.127 |
2.077 |
2.085 |
1.965 |
1.856 |
| *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: (5/7/20 - 5/13/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 103.2 |
103.1 |
101.1 |
| Dry production | 91.8 |
91.6 |
89.3 |
| Net Canada imports | 4.2 |
3.5 |
4.3 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 96.0 |
95.2 |
93.7 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (5/7/20 - 5/13/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 67.3 |
61.6 |
63.1 |
| Power | 24.0 |
24.3 |
25.0 |
| Industrial | 22.0 |
21.4 |
22.1 |
| Residential/commercial | 21.3 |
15.9 |
16.0 |
| Mexico exports | 4.7 |
4.5 |
4.9 |
| Pipeline fuel use/losses | 6.2 |
6.1 |
6.0 |
| LNG pipeline receipts | 7.1 |
7.7 |
5.7 |
| Total demand | 85.3 |
79.8 |
79.8 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, May 05, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 292 |
-10.2% |
-63.7% |
| Natural gas rigs | 80 |
-1.2% |
-56.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, May 05, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 9 |
-18.2% |
-80.0% |
| Horizontal | 338 |
-9.6% |
-61.2% |
| Directional | 27 |
17.4% |
-62.0% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-05-08 |
2020-05-01 |
change |
|
| East | 452 |
424 |
28 |
|
| Midwest | 554 |
530 |
24 |
|
| Mountain | 117 |
111 |
6 |
|
| Pacific | 240 |
228 |
12 |
|
| South Central | 1,059 |
1,027 |
32 |
|
| Total | 2,422 |
2,319 |
103 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (5/8/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 321 |
40.8 |
351 |
28.8 |
|
| Midwest | 328 |
68.9 |
408 |
35.8 |
|
| Mountain | 81 |
44.4 |
124 |
-5.6 |
|
| Pacific | 171 |
40.4 |
239 |
0.4 |
|
| South Central | 722 |
46.7 |
887 |
19.4 |
|
| Total | 1,623 |
49.2 |
2,009 |
20.6 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending May 07) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 76 |
-12 |
-6 |
0 |
0 |
0 |
||
| Middle Atlantic | 73 |
1 |
23 |
0 |
-1 |
0 |
||
| E N Central | 88 |
11 |
17 |
0 |
-3 |
0 |
||
| W N Central | 69 |
2 |
-10 |
3 |
-3 |
3 |
||
| South Atlantic | 39 |
8 |
36 |
28 |
2 |
-28 |
||
| E S Central | 34 |
7 |
26 |
20 |
3 |
-17 |
||
| W S Central | 5 |
-4 |
0 |
60 |
20 |
14 |
||
| Mountain | 51 |
-29 |
-22 |
26 |
13 |
14 |
||
| Pacific | 20 |
-29 |
-20 |
7 |
1 |
7 |
||
| United States | 53 |
-4 |
6 |
16 |
2 |
-3 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending May 07, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending May 07, 2020
Source: National Oceanic and Atmospheric Administration
