In the News:
Plains Midstream Canada enters into an agreement to expand ownership in North America’s largest natural gas processing center
On September 28, 2020, Inter Pipeline Ltd. announced a deal with Plains Midstream Canada (PMC) that would give PMC a greater ownership stake at two natural gas processing plants in Empress, Alberta. The transaction is slated to be completed in early 2021. There are three processing plant complexes in Empress—one with multiple natural gas processing plants. These facilities currently have a combined operable capacity to process up to 9.8 billion cubic feet per day (Bcf/d) of natural gas, making Empress North America’s largest natural gas processing center. These natural gas processing plants play a unique role in North America’s natural gas infrastructure network.
The natural gas processing plants at Empress process all natural gas flowing east out of Alberta. In 2019, the Empress plants processed 4.3 Bcf/d of natural gas, separating out 132,000 barrels per day (b/d) of natural gas plant liquids (NGPL), including 68,000 b/d of ethane, and sending out 4.1 Bcf/d of dry natural gas. Natural gas processing at Empress takes place at three sites:
- PMC-operated Empress (also known as the Amoco plant), which has three natural gas processing plants: Empress I (2.5 Bcf/d capacity), Empress II (2.6 Bcf/d capacity), and Empress V (1.1 Bcf/d capacity)
- PMC-operated Empress 6 (also known as the Petro-Can site), which has one 2.4 Bcf/d processing plant
- Pembina-operated PanCdn Empress processing plant, which has 1.2 Bcf/d of capacity
Unlike most natural gas processing plants, however, the plants at Empress, and three similar sites elsewhere in Alberta, do not process natural gas delivered from a gathering system. Rather, the facilities, called straddle plants, process natural gas that is already flowing on the NOVA Gas Transmission LTD (NGTL) natural gas pipeline system and extract natural gas plant liquids (NGPL)—primarily ethane—that were not removed at natural gas processing plants in the production areas of Alberta. From Empress, the processed natural gas then leaves Alberta on either the Foothills SK pipeline, which delivers natural gas into the Northern Border pipeline at Port of Morgan, Montana, or on the Trans Canada Mainline (TCPL Mainline) to eastern Canada, which also serves the U.S. Midwest via the Great Lakes pipeline and other connecting pipelines.
NGPL produced at Empress are moved to market on three other pipelines:
- PMC’s Plains Petroleum Transport Company (PPTC) pipeline, which delivers propane as far east as Winnipeg, Manitoba
- PMC’s Empress/Kerrobert pipeline, which delivers diluent (natural gasoline) to blend into crude oil at Kerrobert, Saskatchewan, and a propane/butane mix to be shipped on the Enbridge Line 1
- Pembina’s Alberta Ethane Gathering System (AEGS), which delivers ethane to Alberta’s petrochemical plants
Overview:
(For the week ending Wednesday, October 28, 2020)
- Natural gas spot prices rose at most locations this report week (Wednesday, October 21 to Wednesday, October 28). The Henry Hub spot price rose from $2.86 per million British thermal units (MMBtu) last Wednesday to $3.06/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the November 2020 contract expired yesterday at $2.996/MMBtu, down 3¢/MMBtu from last Wednesday. The December 2020 contract price decreased to $3.291/MMBtu, down 6¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging December 2020 through November 2021 futures contracts declined 3¢/MMBtu to $3.108/MMBtu.
- The net injections to working gas totaled 29 billion cubic feet (Bcf) for the week ending October 23. Working natural gas stocks totaled 3,955 Bcf, which is 8% more than the year-ago level and 8% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 8¢/MMBtu, averaging $5.15/MMBtu for the week ending October 28. The prices of natural gasoline and ethane fell by 6% and 1%, respectively. The prices of butane and isobutane both rose by 1%. The price of propane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, October 20, the natural gas rig count decreased by 1 to 73. The number of oil-directed rigs rose by 6 to 211. The total rig count increased by 5, and it now stands at 287.
Prices/Supply/Demand:
Prices rise at most trading hubs outside of California. This report week (Wednesday, October 21 to Wednesday, October 28), the Henry Hub spot price rose 20¢ from a low of $2.86/MMBtu last Wednesday to $3.06/MMBtu yesterday, the highest spot price since March 2019. Temperatures were cooler than normal across most of the Lower 48 states and warmer than normal on the eastern seaboard, especially the Southeast. At the Chicago Citygate, the price increased 32¢ from a low of $2.72/MMBtu last Wednesday to $3.04/MMBtu yesterday.
Hurricane Zeta makes landfall in Louisiana yesterday. Hurricane Zeta made landfall near Cocodrie, Louisiana, yesterday afternoon as a Category 2 storm. Based on operator reports, the Bureau of Safety and Environmental Enforcement (BSEE) estimates that 45% of natural gas production and 67% of oil production in the Gulf of Mexico have been shut-in as of yesterday. High winds cut power to approximately 800,000 customers in Louisiana, Mississippi, and Alabama. More than 80% of customers in New Orleans lost power, according Entergy, the largest utility company.
California prices fall as the West continues to battle wildfires. The price at PG&E Citygate in Northern California fell 15¢, down from a high of $4.26/MMBtu last Wednesday to $4.11/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased 72¢ from $4.35/MMBtu last Wednesday to $3.63/MMBtu yesterday. The state continues to battle over a dozen active wildfires, with active blazes also in neighboring western states.
Northeast prices rise with forecasts of cold temperatures. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $3.10 from $1.74/MMBtu last Wednesday to a high of $4.84/MMBtu yesterday, the highest price since January 2020. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased $1.47 from $0.91/MMBtu last Wednesday to a high of $2.38/MMBtu yesterday.
The Tennessee Zone 4 Marcellus spot price increased $1.08 from $0.62/MMBtu last Wednesday to $1.70/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania rose $1.13 from $0.75/MMBtu last Wednesday to $1.88/MMBtu yesterday.
Permian Basin discount to the Henry Hub narrows considerably. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $0.89/MMBtu last Wednesday, $1.97/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged a high of $2.91/MMBtu, 15¢/MMBtu lower than the Henry Hub price. S&P Platts reports that tighter supply and demand balances in the Southeast and cooler-than-normal temperatures in downstream demand markets in the western U.S. could be boosting prices in the Permian Basin.
Supply is down slightly. 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 1.3% compared with the previous report week. Average net imports from Canada averaged 4.6 Bcf/d during the report week, an increase of 31.9% from last week, according to IHS Markit amid heating demand in Midwestern markets.
Demand rises because of cooler temperatures and increased heating demand in buildings. Total U.S. consumption of natural gas rose by 7.0% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 1.0% week over week. In the residential and commercial sectors, consumption increased by 26.5%, reaching a high of 26.5 Bcf/d on Tuesday, the highest levels since April 2020. Industrial sector consumption increased by 3.2% week over week. Natural gas exports to Mexico decreased 1.9%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 9.0 Bcf/d, or 1.1 Bcf/d higher than last week.
U.S. LNG exports increase week over week. Sixteen LNG vessels (seven from Sabine Pass, three from Cameron, two each from Freeport and Corpus Christi, and one each from Cove Point and Elba Island) with a combined LNG-carrying capacity of 58 Bcf departed the United States between October 22 and October 28, 2020, according to shipping data provided by Marine Traffic.
Storage:
The net injections into storage totaled 29 Bcf for the week ending October 23, compared with the five-year (2015–19) average net injections of 67 Bcf and last year's net injections of 89 Bcf during the same week. Working natural gas stocks totaled 3,955 Bcf, which is 289 Bcf more than the five-year average and 285 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 17 Bcf to 45 Bcf, with a median estimate of 37 Bcf.
The average rate of injections into storage is 1% lower 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 7.1 Bcf/d for the remainder of the refill season, the total inventory would be 4,012 Bcf on October 31, which is 289 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, 22-Oct |
Fri, 23-Oct |
Mon, 26-Oct |
Tue, 27-Oct |
Wed, 28-Oct |
|---|---|---|---|---|---|
| Henry Hub |
2.88 |
2.90 |
3.08 |
3.04 |
3.06 |
| New York |
0.74 |
1.11 |
2.05 |
1.75 |
2.38 |
| Chicago |
2.97 |
2.97 |
3.14 |
3.03 |
3.04 |
| Cal. Comp. Avg.* |
3.53 |
3.47 |
3.77 |
3.88 |
3.60 |
| Futures ($/MMBtu) | |||||
| November contract | 3.007 |
2.971 |
3.024 |
3.019 |
2.996 |
| December contract |
3.272 |
3.195 |
3.253 |
3.311 |
3.291 |
| *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: (10/22/20 - 10/28/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 98.5 |
99.8 |
108.0 |
| Dry production | 87.3 |
88.5 |
96.0 |
| Net Canada imports | 4.6 |
3.5 |
4.1 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 92.0 |
92.0 |
100.2 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (10/22/20 - 10/28/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 72.1 |
67.3 |
67.4 |
| Power | 28.9 |
29.2 |
29.2 |
| Industrial | 22.4 |
21.7 |
21.8 |
| Residential/commercial | 20.7 |
16.4 |
16.4 |
| Mexico exports | 5.8 |
5.9 |
5.3 |
| Pipeline fuel use/losses | 6.8 |
6.7 |
7.2 |
| LNG pipeline receipts | 9.0 |
7.9 |
7.0 |
| Total demand | 93.6 |
87.8 |
86.9 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, October 20, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 211 |
2.9% |
-69.7% |
| Natural gas rigs | 73 |
-1.4% |
-45.1% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, October 20, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 21 |
0.0% |
-58.8% |
| Horizontal | 245 |
2.1% |
-66.3% |
| Directional | 21 |
0.0% |
-58.8% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-10-23 |
2020-10-16 |
change |
|
| East | 941 |
923 |
18 |
|
| Midwest | 1,118 |
1,105 |
13 |
|
| Mountain | 245 |
245 |
0 |
|
| Pacific | 323 |
323 |
0 |
|
| South Central | 1,329 |
1,329 |
0 |
|
| Total | 3,955 |
3,926 |
29 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (10/23/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 909 |
3.5 |
900 |
4.6 |
|
| Midwest | 1,088 |
2.8 |
1,064 |
5.1 |
|
| Mountain | 210 |
16.7 |
215 |
14.0 |
|
| Pacific | 298 |
8.4 |
315 |
2.5 |
|
| South Central | 1,165 |
14.1 |
1,172 |
13.4 |
|
| Total | 3,670 |
7.8 |
3,666 |
7.9 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Oct 22) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 72 |
-37 |
-26 |
0 |
0 |
0 |
||
| Middle Atlantic | 64 |
-33 |
-26 |
0 |
0 |
0 |
||
| E N Central | 114 |
10 |
19 |
0 |
-1 |
0 |
||
| W N Central | 156 |
53 |
53 |
0 |
-1 |
0 |
||
| South Atlantic | 35 |
-21 |
-20 |
33 |
10 |
2 |
||
| E S Central | 38 |
-16 |
-20 |
16 |
8 |
13 |
||
| W S Central | 15 |
-7 |
-9 |
48 |
23 |
21 |
||
| Mountain | 81 |
-18 |
-23 |
19 |
10 |
9 |
||
| Pacific | 14 |
-25 |
-12 |
26 |
20 |
16 |
||
| United States | 68 |
-8 |
-3 |
18 |
8 |
7 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Oct 22, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Oct 22, 2020
Source: National Oceanic and Atmospheric Administration
