In the News:
As solar-powered generation increases in California, natural gas helps meet evening peak demand
In California, the daily need for natural gas-fired generation between 4:00 p.m. and 6:00 p.m. has grown as solar-powered generation has increased. In months when the daily share of solar generation between 10:00 a.m. and 2:00 p.m. averaged 30% to 40% of the generation fuel mix, natural gas-fired generation increased by 2.5 to 4.5 gigawatthours (GWh) between 4:00 p.m. and 6:00 p.m., according to data from EIA’s Hourly and Daily Balancing Authority Operations Report (EIA-930).
California had installed more than 20 gigawatts (GW) of solar capacity as of January of 2020, and more than half of that was utility-scale capacity, more than any other state. Solar-powered generation is typically highest in late morning and early afternoon hours, requiring a combination of other generation fuels, electricity storage, or imports to serve peak demand in the early evening. Because of this requirement, natural gas remains a primary fuel to meet state electricity demand as load and resource availability shifts during the day.
Electricity demand is typically highest in California during the summer months (June–September) as high temperatures drive demand for space cooling. In the summer of 2018, when solar generation averaged between 20% and 30% of the midday generation share, approximately 2.0 GWh of additional natural gas-fired generation was needed to meet peak demand. However, in July 2020, when solar generation averaged 35% of the generation fuel mix, the California Independent System Operator (CAISO) and other balancing authorities needed, on average, 3.7 GW more natural-gas fired generation during those two hours. For several days in the summer of 2020, more than 5.5 GW of natural gas-fired capacity ramped up beween 4:00 p.m. and 6:00 p.m. to meet higher-than-average peak demand.
Hourly generation data also show different seasonal trends in natural gas-fired generation and its dispatch in response to daily changes in electricity supply and demand. Although California’s electricity demand is lowest in winter (December–March), more natural gas-fired generation is needed from 4:00 p.m. to 6:00 p.m. due to lower generation from renewable fuels relative to other months, such as wind and hydroelectricity. Electricity imports from other U.S. regions also play a greater role in meeting peak evening demand during winter. In the summer months, the demand for natural gas-fired generation during this period is lower, because increased hydroelectric power ramps up to meet peak evening demand, and wind power is typically at its highest during summer evening and overnight hours. In the shoulder months, defined here as April, May, October, and November, additional wind and hydroelectric resources, combined with lower electricity demand and higher electricity imports during the early evening, reduce the need for natural gas to balance the electric grid.
Overview:
(For the week ending Wednesday, November 04, 2020)
- Natural gas spot prices fell at most locations this report week (Wednesday, October 28 to Wednesday, November 4). The Henry Hub spot price fell from $3.06 per million British thermal units (MMBtu) last Wednesday to $2.60/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the November 2020 contract expired last Wednesday at $2.996/MMBtu. The December 2020 contract price decreased to $3.046/MMBtu, down 25¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging December 2020 through November 2021 futures contracts declined 11¢/MMBtu to $3.001/MMBtu.
- The net withdrawals from working gas totaled 36 billion cubic feet (Bcf) for the week ending October 30, the first withdrawal of the 2020-2021 heating season. Working natural gas stocks totaled 3,919 Bcf, which is 5% more than the year-ago level and 5% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 1¢/MMBtu, averaging $5.18/MMBtu for the week ending November 4. The prices of natural gasoline and ethane fell by 4% and 1%, respectively. The prices of propane, butane, and isobutane rose by 1%, 5%, and 2%, respectively.
- According to Baker Hughes, for the week ending Tuesday, October 27, the natural gas rig count decreased by 1 to 72. The number of oil-directed rigs rose by 10 to 221. The total rig count increased by 9, and it now stands at 296.
Prices/Supply/Demand:
Prices fall at most locations amid mild autumn temperatures. This report week (Wednesday, October 28 to Wednesday, November 4), the Henry Hub spot price fell 46¢ from a high of $3.06/MMBtu last Wednesday to a low of $2.60/MMBtu yesterday. Temperatures were generally cooler than normal east of the Mississippi River and warmer than normal in the west. At the Chicago Citygate, the price decreased 65¢ from a high of $3.04/MMBtu last Wednesday to a low of $2.39/MMBtu yesterday.
Tropical Depression Eta lingers in the Caribbean Sea. After making landfall as a Category 4 hurricane on Tuesday afternoon in Central America, the National Oceanic and Atmospheric Administration (NOAA) continues to track Tropical Depression Eta in the Gulf of Mexico. As of this morning, the Bureau of Safety and Environmental Enforcement (BSEE) has not issued status reports on U.S. oil and natural gas operators for this storm.
California prices are mixed. The price at SoCal Citygate in Southern California increased $2.13 from $3.63/MMBtu last Wednesday to $5.76/MMBtu yesterday after reaching a high of $5.86 on Tuesday amid warmer-than-normal temperatures. The price at PG&E Citygate in Northern California fell 6¢, down from a high of $4.11/MMBtu last Wednesday to $4.05/MMBtu yesterday.
Northeast prices end week lower than Waha Hub price. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $4.00 from $4.84/MMBtu last Wednesday to a low of $0.84/MMBtu yesterday after reaching a high of $6.54 last Thursday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased $1.74 from $2.38/MMBtu last Wednesday to a low of $0.64/MMBtu yesterday. These large price decreases were the result of almost 20-degreee temperature increases in the Northeast late in the report week that contributed to declines in residential and commercial natural gas consumption. Another contributing factor to the price decrease was the November 1 announcement by Texas Eastern Transmission (TETCO) that maintenance between the Holbrook and Uniontown compressor stations in Pennsylvania was completed, allowing capacity to return to its normal operating capacity of about 4.5 Bcf/d (an increase of about 1.8 Bcf/d).
The Tennessee Zone 4 Marcellus spot price decreased $1.26 from $1.70/MMBtu last Wednesday to $0.44/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell $1.36 from $1.88/MMBtu last Wednesday to $0.52/MMBtu yesterday.
Permian Basin discount to the Henry Hub widens slightly. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged a high of $2.91/MMBtu last Wednesday, 15¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $2.39/MMBtu, 21¢/MMBtu lower than the Henry Hub price. S&P Platts report that strong liquefied natural gas (LNG) feedgas demand has boosted Permian spot prices recently.
Supply rises because of increased production. According to data from IHS Markit, the average total supply of natural gas rose by 1.9% compared with the previous report week. Dry natural gas production grew by 1.5% compared with the previous report week. Average net imports from Canada increased by 8.0% from last week.
Demand rises, driven by LNG exports and heating demand in buildings. Total U.S. consumption of natural gas rose by 1.4% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 12.2% week over week. In the residential and commercial sectors, consumption increased by 20.4% amid cooler-than-normal temperatures on the East Coast. Industrial sector consumption increased by 1.4% week over week. Natural gas exports to Mexico decreased 6.9%. Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged a record high of 10.1 Bcf/d, or 1.1 Bcf/d higher than last week.
U.S. LNG exports increase week over week. Twenty-two LNG vessels (nine from Sabine Pass, four each from Corpus Christi and Freeport, three from Cameron, and two from Cove Point) with a combined LNG-carrying capacity of 82 Bcf departed the United States between October 29 and November 4, 2020, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net withdrawals from storage totaled 36 Bcf for the week ending October 30, compared with the five-year (2015–19) average net injections of 52 Bcf and last year's net injections of 49 Bcf during the same week. Working natural gas stocks totaled 3,919 Bcf, which is 201 Bcf more than the five-year average and 200 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 withdrawals of 17 Bcf to 38 Bcf, with a median estimate of 28 Bcf
More storage data and analysis can be found on the Natural Gas Storage Dashboard and the Weekly Natural Gas Storage Report.
See also:
![Average hourly electric power generation by fuel type, season (Nov. 1, 2018 to Oct. 31, 2020)](img/20201105_itn1.png)
Note: Pacific Standard Time = Coordinated Universal Time minus 8 hours for all months of the year.
![Average daily increase in natural gas-fired generation (4 p.m. - 6 p.m.) and share of solar generation, July 2018 - October 2020](img/20201105_itn2.png)
![Natural gas spot prices](img/20201105_NGSP.png)
Spot Prices ($/MMBtu) | Thu, 29-Oct |
Fri, 30-Oct |
Mon, 02-Nov |
Tue, 03-Nov |
Wed, 04-Nov |
---|---|---|---|---|---|
Henry Hub |
3.00 |
3.04 |
3.00 |
2.84 |
2.60 |
New York |
2.51 |
2.48 |
1.87 |
1.09 |
0.64 |
Chicago |
2.92 |
2.95 |
2.85 |
2.64 |
2.39 |
Cal. Comp. Avg.* |
3.48 |
3.29 |
3.65 |
3.91 |
3.73 |
Futures ($/MMBtu) | |||||
December contract | 3.301 |
3.354 |
3.244 |
3.059 |
3.046 |
January contract |
3.417 |
3.469 |
3.375 |
3.195 |
3.177 |
*Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
Source: NGI's Daily Gas Price Index |
![Natural gas futures prices](img/20201105_NGFP.png)
![Natural gas liquids spot prices](img/20201105_NGLSP.png)
U.S. natural gas supply - Gas Week: (10/29/20 - 11/4/20) | |||
---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
Marketed production | 100.1 |
98.6 |
106.5 |
Dry production | 89.1 |
87.8 |
94.9 |
Net Canada imports | 5.0 |
4.6 |
4.3 |
LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
Total supply | 94.2 |
92.5 |
99.2 |
Source: IHS Markit |
U.S. natural gas consumption - Gas Week: (10/29/20 - 11/4/20) | |||
---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
U.S. consumption | 73.0 |
72.0 |
75.3 |
Power | 25.2 |
28.8 |
28.2 |
Industrial | 22.9 |
22.6 |
22.2 |
Residential/commercial | 24.9 |
20.7 |
24.9 |
Mexico exports | 5.4 |
5.8 |
5.3 |
Pipeline fuel use/losses | 6.9 |
6.8 |
7.4 |
LNG pipeline receipts | 10.1 |
9.0 |
7.5 |
Total demand | 95.5 |
93.7 |
95.5 |
Source: IHS Markit |
![Natural gas supply](img/20201105_Supply.png)
![Weekly natural gas rig count and average Henry Hub](img/20201105_rigs.png)
Rigs | |||
---|---|---|---|
Tue, October 27, 2020 |
Change from |
||
last week |
last year |
||
Oil rigs | 221 |
4.7% |
-68.0% |
Natural gas rigs | 72 |
-1.4% |
-44.6% |
Note: Excludes any miscellaneous rigs |
Rig numbers by type | |||
---|---|---|---|
Tue, October 27, 2020 |
Change from |
||
last week |
last year |
||
Vertical | 20 |
-4.8% |
-61.5% |
Horizontal | 254 |
3.7% |
-64.6% |
Directional | 22 |
4.8% |
-58.5% |
Source: Baker Hughes Co. |
Working gas in underground storage | ||||
---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
Region | 2020-10-30 |
2020-10-23 |
change |
|
East | 947 |
941 |
6 |
|
Midwest | 1,119 |
1,118 |
1 |
|
Mountain | 240 |
245 |
-5 |
|
Pacific | 320 |
323 |
-3 |
|
South Central | 1,293 |
1,329 |
-36 |
|
Total | 3,919 |
3,955 |
-36 |
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report |
Working gas in underground storage | |||||
---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (10/30/19) |
5-year average (2015-2019) |
||||
Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
East | 927 |
2.2 |
908 |
4.3 |
|
Midwest | 1,105 |
1.3 |
1,083 |
3.3 |
|
Mountain | 208 |
15.4 |
216 |
11.1 |
|
Pacific | 294 |
8.8 |
316 |
1.3 |
|
South Central | 1,186 |
9.0 |
1,195 |
8.2 |
|
Total | 3,719 |
5.4 |
3,718 |
5.4 |
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report |
Temperature – heating & cooling degree days (week ending Oct 29) | ||||||||
---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
New England | 100 |
-23 |
7 |
0 |
0 |
0 |
||
Middle Atlantic | 82 |
-31 |
10 |
0 |
0 |
0 |
||
E N Central | 145 |
22 |
17 |
1 |
0 |
1 |
||
W N Central | 221 |
95 |
35 |
0 |
-1 |
0 |
||
South Atlantic | 24 |
-43 |
-11 |
43 |
24 |
5 |
||
E S Central | 34 |
-32 |
-13 |
15 |
11 |
12 |
||
W S Central | 76 |
43 |
14 |
13 |
-6 |
5 |
||
Mountain | 181 |
64 |
1 |
5 |
0 |
1 |
||
Pacific | 52 |
2 |
1 |
0 |
-3 |
-11 |
||
United States | 103 |
12 |
9 |
11 |
4 |
1 |
||
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration |
Average temperature (°F)
7-day mean ending Oct 29, 2020
![Mean Temperature (F) 7-Day Mean ending Oct 29, 2020](img/20201029.7day.mean.F.gif)
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Oct 29, 2020
![Mean Temperature Anomaly (F) 7-Day Mean ending Oct 29, 2020](img/20201029.7day.mean.F.gif)
Source: National Oceanic and Atmospheric Administration