In the News:
Natural gas-fired power generation higher in first half of 2020
Natural gas-fired generation in the Lower 48 states increased nearly 55,000 gigawatthours (GWh), or 9%, in the first half of 2020. Natural gas was the fastest-growing source of electric power generation, according to data from the Hourly Electric Grid Monitor. The increase in natural gas-fired generation, which is the result of recent low prices and natural gas-fired power capacity additions, comes despite a 5% decline in total electricity generation. The decrease in electricity consumption is partially attributable to reduced business activity as a result of COVID-19 mitigation efforts.
Coal-fired generation absorbed most of the decrease in electrical load in the first half of 2020, registering a 138,000 GWh (30%) decline in output. With historically low natural gas prices so far in 2020, coal-fired generation this year has been uneconomic in most regions compared to natural gas-fired generation, leading to price-driven coal-to-gas fuel switching. The monthly Henry Hub spot price averaged $1.81 per million British thermal units (MMBtu) through the first half of the year, compared to an average of $2.74/MMBtu in the first half of 2019.
Coal-to-gas switching was most prominent in the Pennsylvania, Jersey, Maryland Power Pool Interconnection (PJM), which covers an area stretching from New Jersey to Illinois, and the Midcontinent Independent System Operator (MISO), which primarily includes areas in the Midwest. PJM and MISO together make up about 35% of the total Lower 48 states’ electric power generation. In both interconnections, competition exists between natural gas and coal as generation fuels, so relative shifts in fuel prices can influence the type of power plant that is dispatched. At the end of June, the spot prices at the Tetco M3 hub in eastern Pennsylvania and the Chicago Citygate had fallen to $1.58/MMBtu and $1.66/MMBtu, respectively, down nearly 50¢/MMBtu each from last year. As prices have fallen, natural gas-fired generation increased by about 17,000 GWh in PJM and 15,000 GWh in MISO in the first half of 2020, while coal-fired generation declined about 34,000 GWh in PJM and 40,000 GWh in MISO.
Capacity additions have also contributed to the growth in natural gas-fired generation so far in 2020. According to the Electric Power Monthly, about 18,000 megawatts (MW) of net capacity of new combined-cycle natural gas turbine plants have entered service since 2018. Output from these highly efficient plants have been steadily ramping up and helping to drive the latest increase in generation. Over the same 30-month period, about 31,000 MW of net capacity for coal-fired plants have been retired along with about 2,400 MW in net capacity for nuclear power plants.
At the same time, natural gas generation is facing increased competition from solar and wind capacity, where 26,700 MW of new net capacity has been added since 2018. As a result, renewable energy, consisting of wind, solar, and hydroelectric generation, has been the only other source of power generation besides natural gas to experience growth in the first half of 2020, with an increase of about 5%.
Overview:
(For the week ending Wednesday, July 15, 2020)
- Natural gas spot prices fell at most locations this report week (Wednesday, July 8 to Wednesday, July 15). The Henry Hub spot price fell from $1.79 per million British thermal units (MMBtu) last Wednesday to $1.71/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the August 2020 contract decreased 5¢, from $1.824/MMBtu last Wednesday to $1.778/MMBtu yesterday. The price of the 12-month strip averaging August 2020 through July 2021 futures contracts declined 2¢/MMBtu to $2.421/MMBtu.
- The net injections to working gas totaled 45 billion cubic feet (Bcf) for the week ending July 10. Working natural gas stocks totaled 3,178 Bcf, which is 26% more than the year-ago level and 16% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 23¢/MMBtu, averaging $4.78/MMBtu for the week ending July 15. The prices of natural gasoline, ethane, isobutane, propane, and butane all rose, by 12%, 8%, 7%, 2%, and 1%, respectively.
- According to Baker Hughes, for the week ending Tuesday, July 7, the natural gas rig count decreased by 1 to 75. The number of oil-directed rigs fell by 4 to 181. The total rig count decreased by 5, and it now stands at 258.
Prices/Supply/Demand:
Prices are down across the Lower 48 states. This report week (Wednesday, July 8 to Wednesday, July 15), the Henry Hub spot price fell 8¢ from $1.79/MMBtu last Wednesday to $1.71/MMBtu yesterday, with a low of $1.70/MMBtu on Monday. Temperatures were mixed with warmer-than-normal temperatures in the Southwest and cooler-than-normal temperatures in the Pacific Northwest. At the Chicago Citygate, the price decreased 14¢ from a high of $1.82/MMBtu last Wednesday to $1.68/MMBtu yesterday.
California prices fall. The price at PG&E Citygate in Northern California fell 24¢, down from $2.65/MMBtu last Wednesday to $2.41/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased 10¢ from $2.01/MMBtu last Wednesday to a low of $1.91/MMBtu yesterday. The price at SoCal Citygate reached a high of $2.30/MMBtu on Monday amid a period of warm temperatures early in the week that contributed to summer-time storage withdrawals from the Southern California Gas system. In the Pacific region, supply has outpaced demand; and at the mid-point of the summer, underground working natural gas storage for the region is 77% full.
Northeast prices fall on lower power demand. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 24¢ from a high of $1.72/MMBtu last Wednesday to $1.48/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 12¢ from a high of $1.77/MMBtu last Wednesday to $1.65/MMBtu yesterday. According to IHS Markit, natural gas power burn in the Northeast declined 15% yesterday compared to last Wednesday.
The Tennessee Zone 4 Marcellus spot price decreased 15¢ from $1.40/MMBtu last Wednesday to $1.25/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell 6¢ from $1.35/MMBtu last Wednesday to $1.29/MMBtu yesterday. The price at Tetco-M3, located in Eastern Pennsylvania, briefly increased 42¢ on Tuesday to a high of $2.22/MMBtu following capacity restrictions at the Uniontown compressor station on Texas Eastern Transmission. The price declined 58¢ to $1.64/MMBtu on Wednesday as concerns regarding capacity restrictions eased.
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 $1.48/MMBtu last Wednesday, 31¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $1.56/MMBtu, 15¢/MMBtu lower than the Henry Hub price.
Supply falls. According to data from IHS Markit, the average total supply of natural gas fell by 0.1% compared with the previous report week. Dry natural gas production decreased by 0.7% compared with the previous report week. Average net imports from Canada increased by 11.3% from last week amid warmer-than-normal temperatures in Northeastern markets.
Demand rises across all sectors except res/com. Total U.S. consumption of natural gas rose by 0.9% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 1.2% week over week as power generation steadily increased since mid-June. Power burn hit 43.6 Bcf/d on Thursday, the highest daily level since August 2019 before falling back to near 40 Bcf/d by the middle of the report week. Industrial sector consumption increased by 1.3% week over week. In the residential and commercial sectors, consumption declined by 1.3%. Natural gas exports to Mexico increased 5.9%.
U.S. LNG exports decrease week over week. Four liquefied natural gas (LNG) vessels (two from Sabine Pass and one each from Cove Point and Cameron) with a combined LNG-carrying capacity of 15 Bcf departed the United States between July 9 and July 15, 2020, according to shipping data provided by Marine Traffic. This level is the lowest reported U.S. LNG export volume since December 8, 2016, when Sabine Pass LNG was the only U.S. LNG export facility and had two trains in operation.
Storage:
The net injections into storage totaled 45 Bcf for the week ending July 10, compared with the five-year (2015–19) average net injections of 63 Bcf and last year's net injections of 67 Bcf during the same week. Working natural gas stocks totaled 3,178 Bcf, which is 436 Bcf more than the five-year average and 663 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 38 Bcf to 52 Bcf, with a median estimate of 48 Bcf.
The average rate of injections into storage is 12% 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 8.7 Bcf/d for the remainder of the refill season, the total inventory would be 4,159 Bcf on October 31, which is 436 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, 09-Jul |
Fri, 10-Jul |
Mon, 13-Jul |
Tue, 14-Jul |
Wed, 15-Jul |
|---|---|---|---|---|---|
| Henry Hub |
1.82 |
1.75 |
1.72 |
1.70 |
1.71 |
| New York |
1.75 |
1.68 |
1.68 |
1.67 |
1.65 |
| Chicago |
1.79 |
1.71 |
1.71 |
1.67 |
1.68 |
| Cal. Comp. Avg.* |
2.06 |
2.05 |
2.09 |
2.03 |
1.93 |
| Futures ($/MMBtu) | |||||
| August contract | 1.779 |
1.805 |
1.739 |
1.746 |
1.778 |
| September contract |
1.821 |
1.847 |
1.797 |
1.787 |
1.818 |
| *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: (7/9/20 - 7/15/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 100.4 |
101.3 |
101.7 |
| Dry production | 88.9 |
89.5 |
89.3 |
| Net Canada imports | 4.7 |
4.2 |
5.3 |
| LNG pipeline deliveries | 0.2 |
0.1 |
0.1 |
| Total supply | 93.8 |
93.9 |
94.7 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (7/9/20 - 7/15/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 70.0 |
69.4 |
69.5 |
| Power | 41.0 |
40.5 |
41.7 |
| Industrial | 20.4 |
20.1 |
19.4 |
| Residential/commercial | 8.6 |
8.7 |
8.4 |
| Mexico exports | 5.7 |
5.4 |
5.5 |
| Pipeline fuel use/losses | 5.5 |
5.5 |
6.3 |
| LNG pipeline receipts | 3.3 |
3.1 |
5.8 |
| Total demand | 84.4 |
83.4 |
87.0 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, July 07, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 181 |
-2.2% |
-76.9% |
| Natural gas rigs | 75 |
-1.3% |
-56.4% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, July 07, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 19 |
11.8% |
-66.7% |
| Horizontal | 220 |
-2.7% |
-73.5% |
| Directional | 19 |
-5.0% |
-72.9% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-07-10 |
2020-07-03 |
change |
|
| East | 672 |
657 |
15 |
|
| Midwest | 780 |
761 |
19 |
|
| Mountain | 186 |
180 |
6 |
|
| Pacific | 312 |
310 |
2 |
|
| South Central | 1,228 |
1,226 |
2 |
|
| Total | 3,178 |
3,133 |
45 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (7/10/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 556 |
20.9 |
588 |
14.3 |
|
| Midwest | 618 |
26.2 |
647 |
20.6 |
|
| Mountain | 145 |
28.3 |
171 |
8.8 |
|
| Pacific | 267 |
16.9 |
294 |
6.1 |
|
| South Central | 928 |
32.3 |
1,041 |
18.0 |
|
| Total | 2,515 |
26.4 |
2,742 |
15.9 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jul 09) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 1 |
-1 |
0 |
55 |
20 |
-5 |
||
| Middle Atlantic | 0 |
-1 |
0 |
92 |
41 |
15 |
||
| E N Central | 0 |
-1 |
0 |
98 |
46 |
20 |
||
| W N Central | 0 |
-4 |
0 |
92 |
26 |
18 |
||
| South Atlantic | 0 |
0 |
0 |
109 |
15 |
-2 |
||
| E S Central | 0 |
0 |
0 |
104 |
14 |
-10 |
||
| W S Central | 0 |
0 |
0 |
129 |
9 |
-4 |
||
| Mountain | 1 |
-7 |
0 |
81 |
8 |
13 |
||
| Pacific | 5 |
-1 |
2 |
41 |
3 |
9 |
||
| United States | 1 |
-1 |
0 |
91 |
22 |
7 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Jul 09, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Jul 09, 2020
Source: National Oceanic and Atmospheric Administration
