In the News:
Natural gas rig count falls to lowest level since 2016
The number of active natural gas rigs in the United States fell to 85 on April 21, the lowest number of active natural gas rigs since August 2016, according to data from Baker Hughes Company. As of that date, there were 38 fewer (31%) active natural gas rigs than at the beginning of 2020 and 101 fewer (54%) than last year at the same time. Natural gas-directed rigs remained concentrated in the Marcellus Basin in Ohio, Pennsylvania, and West Virginia and in the Haynesville Basin in Louisiana and Texas. These two basins accounted for 50% of the decrease in natural gas-directed rigs over the past year, and 78% of remaining natural gas-directed rigs in the United States operate in these basins.
The natural gas rig count peaked at 202 rigs on January 8, 2019, according to Baker Hughes data, the highest level since 2015. During January 2019, the Henry Hub spot price averaged $3.05 per million British thermal units (MMBtu). By the beginning of 2020, the Henry Hub spot price averaged $2.00/MMBtu, which is historically low for that time of year. One short-term factor contributing to the current low-price environment is lower demand related to unseasonably warm weather. A longer-term factor affecting the price decrease is related to rapid growth in dry natural gas production relative to consumption levels.
Production rose in 2019 even though the rig count decreased, reaching a record-high 96.3 billion cubic feet per day (Bcf/d) of dry natural gas production in November. Since then, dry natural gas production has declined as relatively low natural gas prices have diminished the economic incentive for producers to drill new natural gas wells. Similarly, associated natural gas production has fallen as the lower price of oil has reduced the incentive to drill oil wells. Completion of drilled but uncompleted wells (DUCs) has likely offset some of the decrease in production from newly drilled wells; according to EIA’s most recent Drilling Productivity Report, as of March 2020, the number of DUCs was 13% (1,052 DUCs) lower than the peak in May 2019. This drop indicates that more wells are being completed than are being drilled.
EIA’s latest Short-Term Energy Outlook (STEO) forecasts dry natural gas production to continuing falling through next year from 94.5 Bcf/d in January 2020 to 85.9 Bcf/d in March 2021, after which EIA forecasts production will increase again.
Overview:
(For the week ending Wednesday, April 29, 2020)
- Natural gas spot prices are mixed at most locations this report week (Wednesday, April 22 to Wednesday, April 29). The Henry Hub spot price fell from $1.87 per million British thermal units (MMBtu) last Wednesday to $1.70/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the May 2020 contract expired Tuesday at $1.794/MMBtu, down 15¢/MMBtu from last Wednesday. The June 2020 contract price decreased to $1.869/MMBtu, down 18¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging June 2020 through May 2021 futures contracts declined 7¢/MMBtu to $2.535/MMBtu.
- The net injections to working gas totaled 70 billion cubic feet (Bcf) for the week ending April 24. Working natural gas stocks totaled 2,210 Bcf, which is 55% more than the year-ago level and 19% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 7¢/MMBtu, averaging $3.09/MMBtu for the week ending April 29. The price of ethane rose by 18%. The prices of propane, butane, isobutane, and natural gasoline, fell by 1%, 3%, 5%, and 7%, respectively.
- According to Baker Hughes, for the week ending Tuesday, April 21, the natural gas rig count decreased by 4 to 85. The number of oil-directed rigs fell by 60 to 378. The total rig count decreased by 64, and it now stands at 465.
Prices/Supply/Demand:
Prices decrease at major trading hubs with spring temperatures. This report week (Wednesday, April 22 to Wednesday, April 29), the Henry Hub spot price fell 17¢ from a high of $1.87/MMBtu last Wednesday to $1.70/MMBtu yesterday. Temperatures were generally cooler than normal east of the Rocky Mountains and warmer than normal to the west, especially in California and the Southwest. At the Chicago Citygate, the price decreased 20¢ from a high of $1.85/MMBtu last Wednesday to $1.65/MMBtu yesterday.
California prices are up with unseasonably warm temperatures. California experienced much warmer-than-normal weather, with temperatures averaging 85 degrees Fahrenheit (°F) in Southern California and 8°F to 10°F higher than normal across the northern part of the state. The price at SoCal Citygate in Southern California increased 17¢ from $1.69/MMBtu last Wednesday to $1.86/MMBtu yesterday. Amid increased cooling demand, prices also faced upward pressure as flows into Southern California markets were restricted by ongoing maintenance on the El Paso Natural Gas Pipeline and its declaration of a force majeure at the Topock compressor station in San Bernardino County, which went into effect yesterday. The price at PG&E Citygate in Northern California rose 9¢, up from $2.30/MMBtu last Wednesday to $2.39/MMBtu yesterday.
Northeastern prices decline during the week with moderate spring temperatures. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 33¢ from a high of $1.99/MMBtu last Wednesday to a low of $1.66/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 26¢ from a high of $1.81/MMBtu last Wednesday to a low of $1.55/MMBtu yesterday.
The Tennessee Zone 4 Marcellus spot price decreased 23¢ from $1.61/MMBtu last Wednesday to $1.38/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell 12¢ from $1.62/MMBtu last Wednesday to $1.50/MMBtu yesterday.
Permian Basin prices strengthen relative to the Henry Hub, trading in positive territory throughout the week. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $1.21/MMBtu last Wednesday, 66¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $1.32/MMBtu, 38¢/MMBtu lower than the Henry Hub price. Prices reached a high of $1.328/MMBtu on Tuesday, and a low of 69¢/MMBtu on Friday.
Supply is down. According to data from IHS Markit, the average total supply of natural gas fell by 1.0% compared with the previous report week. Dry natural gas production decreased by 0.5% compared with the previous report week. Average net imports from Canada decreased by 12.0% from last week as imports into the U.S. Pacific Northwest from Western Canada declined, especially at the Sumas border crossing point. Canadian producers may also be undergoing their annual spring maintenance when they reduce production activities as a result of warming weather and more difficult terrain.
Demand falls, driven by power demand and consumption in buildings. Total U.S. consumption of natural gas fell by 3.8% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 1.9% week over week. In the residential and commercial sectors, consumption declined by 8.5% with seasonal temperatures. Industrial sector consumption decreased by 1.1% week over week. Natural gas exports to Mexico increased 2.7%.
U.S. LNG exports decrease week over week. Eleven LNG vessels (six from Sabine Pass, two from Cameron and one each from Freeport, Cove Point and Corpus Christi) with a combined LNG-carrying capacity of 39 Bcf departed the United States between April 23 and April 29, 2020, according to shipping data compiled by Bloomberg. One vessel was loading at the Freeport terminal on Wednesday.
On Wednesday, the Natural Gas Pipeline Company of America declared a force majeure at the delivery point into the Sabine Pass liquefaction facility because of storm damage. Until maintenance is completed, flows will fall to 0.0 Bcf/d from an average of 0.59 Bcf/d during the past two weeks.
Storage:
The net injections into storage totaled 70 Bcf for the week ending April 24, compared with the five-year (2015–19) average net injections of 74 Bcf and last year's net injections of 114 Bcf during the same week. Working natural gas stocks totaled 2,210 Bcf, which is 360 Bcf more than the five-year average and 783 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 64 Bcf to 82 Bcf, with a median estimate of 71 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, 23-Apr |
Fri, 24-Apr |
Mon, 27-Apr |
Tue, 28-Apr |
Wed, 29-Apr |
|---|---|---|---|---|---|
| Henry Hub | 1.85 | 1.77 | 1.65 | 1.80 | 1.70 |
| New York | 1.79 | 1.64 | 1.57 | 1.69 | 1.55 |
| Chicago | 1.83 | 1.76 | 1.68 | 1.72 | 1.65 |
| Cal. Comp. Avg.* | 1.91 | 1.81 | 1.85 | 2.02 | 1.93 |
| Futures ($/MMBtu) | |||||
| May Contract | 1.815 | 1.746 | 1.819 | 1.794 | Expired |
| June Contract | 1.942 | 1.895 | 1.916 | 1.948 | 1.869 |
| July Contract | 2.155 | 2.128 | 2.153 | 2.170 | 2.091 |
| *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: (4/23/20 - 4/29/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 105.0 |
105.5 |
100.4 |
| Dry production | 92.9 |
93.3 |
89.4 |
| Net Canada imports | 3.7 |
4.2 |
4.0 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 96.6 |
97.6 |
93.5 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (4/23/20 - 4/29/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 64.1 |
66.6 |
64.4 |
| Power | 23.9 |
24.4 |
24.4 |
| Industrial | 20.0 |
20.2 |
22.0 |
| Residential/commercial | 20.1 |
22.0 |
18.0 |
| Mexico exports | 4.8 |
4.6 |
4.8 |
| Pipeline fuel use/losses | 6.3 |
6.4 |
6.2 |
| LNG pipeline receipts | 7.4 |
8.2 |
4.8 |
| Total demand | 82.5 |
85.9 |
80.1 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, April 21, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 378 |
-13.7% |
-53.0% |
| Natural gas rigs | 85 |
-4.5% |
-54.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, April 21, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 16 |
-52.9% |
-76.5% |
| Horizontal | 426 |
-40.1% |
-53.8% |
| Directional | 23 |
-48.9% |
-60.3% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-04-24 |
2020-04-17 |
change |
|
| East | 405 |
400 |
5 |
|
| Midwest | 506 |
493 |
13 |
|
| Mountain | 103 |
96 |
7 |
|
| Pacific | 218 |
210 |
8 |
|
| South Central | 979 |
941 |
38 |
|
| Total | 2,210 |
2,140 |
70 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (4/24/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 271 |
49.4 |
306 |
32.4 |
|
| Midwest | 283 |
78.8 |
373 |
35.7 |
|
| Mountain | 74 |
39.2 |
117 |
-12.0 |
|
| Pacific | 148 |
47.3 |
224 |
-2.7 |
|
| South Central | 652 |
50.2 |
830 |
18.0 |
|
| Total | 1,427 |
54.9 |
1,850 |
19.5 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Apr 23) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 166 |
45 |
104 |
0 |
0 |
0 |
||
| Middle Atlantic | 152 |
47 |
106 |
0 |
0 |
0 |
||
| E N Central | 149 |
42 |
66 |
0 |
0 |
0 |
||
| W N Central | 116 |
18 |
44 |
0 |
-1 |
0 |
||
| South Atlantic | 74 |
25 |
47 |
27 |
9 |
8 |
||
| E S Central | 63 |
18 |
20 |
1 |
-4 |
-4 |
||
| W S Central | 23 |
4 |
0 |
34 |
10 |
10 |
||
| Mountain | 104 |
0 |
37 |
5 |
-4 |
-8 |
||
| Pacific | 58 |
-3 |
28 |
0 |
-4 |
-2 |
||
| United States | 104 |
23 |
52 |
9 |
1 |
1 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Apr 23, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Apr 23, 2020
Source: National Oceanic and Atmospheric Administration
