In the News:
U.S. natural gas bills will increase in all regions this winter
In our latest Winter Fuels Outlook, we forecast that U.S. households that primarily use natural gas for space heating will spend an average of $931 on heating this winter (October–March), which is $206, or 28%, more than last year.
Natural gas is the primary heating fuel for 47% of U.S. homes, according to the U.S. Census Bureau’s 2021 American Community Survey. The retail price of natural gas and the amount of natural gas consumed largely determine how much households spend on winter natural gas bills.
Higher retail natural gas prices are the main driver for the expected increase in natural gas heating expenditures this winter. On average, retail natural gas prices in the United States are expected to rise from $13.02 per thousand cubic feet (Mcf) last winter to $15.95/Mcf this winter, a 22% increase. We expect the largest increase on a percentage basis in retail natural gas prices to occur in the Midwest, where prices rise to $13.80/Mcf, a 27% increase compared with last winter.
The increase in retail prices reflects rising natural gas spot prices over the past year. For example, the natural gas spot price at the U.S. benchmark Henry Hub will average $7.26 per million British thermal units this winter, up 54% from last winter. Changes in natural gas spot prices typically get passed through to retail prices over a period of months because of regulatory rate structures. Utilities generally cannot profit or lose money from natural gas commodity sales, the costs of which are passed through directly to the consumer.
In addition to any changes in natural gas spot prices, price spikes from previous years can also affect current retail prices. For example, regional natural gas spot prices approached record highs following Winter Storm Uri in February 2021, especially in the Midwest. Following that wholesale price spike, spot prices quickly returned to pre-winter-storm levels. Many utility companies in states affected by the storm filed motions with their states’ public utility commissions detailing plans to recover costs that they had incurred as a result of the extremely high wholesale natural gas costs following the winter storm. For example, in Colorado, these plans involve adding a line item charge to utility bills for the next several years to spread the cost out over a long period of time.
Higher natural gas expenditures this winter will also result from slightly higher expected consumption compared with last year. For households that use natural gas as their primary space heating fuel, we expect average consumption this winter to be 58.4 Mcf, a 5% increase from last winter. The higher consumption is driven by colder temperatures compared with last winter. We expect a 6% increase in the number of heating degree days (a measure of heating demand) this winter compared with last winter.
Market Highlights:
(For the week ending Wednesday, October 12, 2022)Prices
- Henry Hub spot price: The Henry Hub spot price rose 41 cents from $6.06 per million British thermal units (MMBtu) last Wednesday to $6.47/MMBtu yesterday.
- Henry Hub futures prices: The price of the November 2022 NYMEX contract decreased 49.5 cents, from $6.930/MMBtu last Wednesday to $6.435/MMBtu yesterday. The price of the 12-month strip averaging November 2022 through October 2023 futures contracts declined 9.7 cents to $5.733/MMBtu.
- Select regional spot prices: Natural gas spot prices declined at most locations this report week (Wednesday, October 5, to Wednesday, October 12). Week-over-week price declines at major pricing hubs ranged from 83 cents/MMBtu at Malin near the California-Oregon border to 5 cents/MMBtu at Algonquin Citygate near Boston, while price increases ranged from 3 cents/MMBtu at SoCal Citygate in Southern California to 97 cents/MMBtu at the Waha Hub in western Texas.
- In the Midwest, at the Chicago Citygate, the price decreased 33 cents from $6.17/MMBtu last Wednesday to $5.84/MMBtu yesterday, fluctuating with temperatures during the week. After reaching a high for the report week of $6.37/MMBtu on Thursday ahead of colder weekend temperatures, the Chicago Citygate price subsequently fell to a low for the report week of $5.37/MMBtu on Tuesday as temperatures increased to above normal, reducing heating demand. In the Chicago Area, temperatures averaged 56°F this report week, leading to 61 heating degree days (HDD). On Saturday, October 8, the daily temperature averaged 48°F, 9°F lower than normal. Natural gas consumption in the combined residential and commercial sectors in the Midwest increased by 25% (0.7 billion cubic feet per day [Bcf/d]) week over week, according to data from PointLogic, while natural gas consumption in the electric power sector declined by 6% (0.2 Bcf/d).
- In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price decreased 5 cents from $6.03/MMBtu last Wednesday to $5.98/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 55 cents from $5.97/MMBtu last Wednesday to $5.42/MMBtu yesterday. Despite below-normal temperatures in the Northeast region over the weekend, temperatures were higher on average this report week than last report week. Across the Northeast region, natural gas consumption in the residential and commercial sectors declined by 7% (0.4 Bcf/d) this report week, while total consumption declined by 3% (0.4 Bcf/d), according to data from PointLogic.
- In California, against the general trend, the price at PG&E Citygate in Northern California rose 15 cents, up from $7.91/MMBtu last Wednesday to $8.06/MMBtu yesterday, and the price at SoCal Citygate in Southern California increased 3 cents from $7.98/MMBtu last Wednesday to $8.01/MMBtu yesterday. Temperatures throughout the West Coast region were higher than normal this week, resulting in elevated air-conditioning demand. Natural gas consumption in the electric power sector in California increased 10% (0.2 Bcf/d) this report week.
- International futures prices: International natural gas futures prices declined this report week. According to Bloomberg Finance, L.P., weekly average futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased $3.18 to a weekly average of $34.81/MMBtu, and natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased $5.17 to a weekly average of $45.83/MMBtu.
- Natural gas plant liquids prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose 27 cents/MMBtu, averaging $9.17/MMBtu for the week ending October 12. The price of ethane rose 7%, while the natural gas price at the Houston Ship Channel rose 14%. The ethane premium to natural gas narrowed by 29%. The price of ethylene fell 4%, narrowing the ethylene to ethane premium by 22%. The natural gasoline price rose 4%, following the price of Brent crude oil, which rose 6%. The propane price remained unchanged. The increase in the price of Brent crude oil widened the propane discount to crude oil by 15%. The normal butane price and isobutane price each rose 2%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from PointLogic, the average total supply of natural gas fell by 1.1% (1.1 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.4% (0.4 Bcf/d) compared with the previous report week. Average net imports from Canada decreased by 11.9% (0.7 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas rose by 3.2% (2.1 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation climbed by 4.5% (1.3 Bcf/d) week over week. Industrial sector consumption remained relatively flat week over week, while consumption in the residential and commercial sectors increased by 5.6% (0.8 Bcf/d). Natural gas exports to Mexico decreased 1.0% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 10.8 Bcf/d, or 0.5 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Natural gas deliveries to LNG export terminals in South Louisiana declined by 0.3 Bcf/d to 8.1 Bcf/d, while deliveries to South Texas were relatively flat at 2.3 Bcf/d, according to data from PointLogic. At the Cove Point terminal in Maryland, natural gas deliveries declined by 0.2 Bcf/d to 0 Bcf/d this week, as the terminal continues three weeks of annual planned maintenance that began on October 1. Overall natural gas deliveries to U.S. LNG export terminals decreased by 0.5 Bcf/d week over week to average 10.8 Bcf/d this report week.
- Vessels departing U.S. ports: Nineteen LNG vessels (eight from Sabine Pass, five from Corpus Christi, four from Cameron, and two from Calcasieu Pass) with a combined LNG-carrying capacity of 70 Bcf departed the United States between October 6 and October 12, according to shipping data provided by Bloomberg Finance, L.P.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, October 4, the natural gas rig count decreased by 1 rig from a week ago to 158 rigs. The Marcellus added one rig, and the Haynesville and an unidentified producing region each dropped one rig. The number of oil-directed rigs decreased by 2 rigs from a week ago to 602 rigs. The Permian added one rig, and unidentified producing regions dropped three rigs. The total rig count, which includes 2 miscellaneous rigs, now stands at 762 rigs, which is 229 more than the same week last year.
Storage
- The net injections into storage totaled 125 Bcf for the week ending October 7, compared with the five-year (2017–2021) average net injections of 82 Bcf and last year's net injections of 86 Bcf during the same week. Working natural gas stocks totaled 3,231 Bcf, which is 221 Bcf (6%) lower than the five-year average and 126 Bcf (4%) lower 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 116 Bcf to 137 Bcf, with a median estimate of 129 Bcf.
- The average rate of injections into storage is 3% 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 8.0 Bcf/d for the remainder of the refill season, the total inventory would be 3,424 Bcf on October 31, which is 221 Bcf lower than the five-year average of 3,645 Bcf for that time of year.
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Data source: U.S. Energy Information Administration, Winter Fuels Outlook
Note: winter = October–March
Data source: U.S. Energy Information Administration, Winter Fuels Outlook
Note: winter = October–March
Data source: U.S. Energy Information Administration, Winter Fuels Outlook
Note: winter = October–March
| Spot Prices ($/MMBtu) | Thu, 06-Oct |
Fri, 07-Oct |
Mon, 10-Oct |
Tue, 11-Oct |
Wed, 12-Oct |
|---|---|---|---|---|---|
| Henry Hub |
6.91 |
6.22 |
6.25 |
6.31 |
6.47 |
| New York |
5.94 |
5.47 |
5.39 |
5.13 |
5.42 |
| Chicago |
6.37 |
5.60 |
5.56 |
5.37 |
5.84 |
| Cal. Comp. Avg.* |
7.04 |
6.33 |
6.58 |
6.66 |
6.85 |
| Futures ($/MMBtu) | |||||
| November contract | 6.972 |
6.748 |
6.435 |
6.596 |
6.435 |
| December contract |
7.242 |
7.047 |
6.784 |
6.928 |
6.766 |
| Data source: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. |
|||||
| U.S. natural gas supply - Gas Week: (10/6/22 - 10/12/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 112.1 |
112.6 |
106.5 |
| Dry production | 99.9 |
100.3 |
96.3 |
| Net Canada imports | 5.4 |
6.1 |
4.9 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 105.4 |
106.5 |
101.3 |
|
Data source: PointLogic | |||
| U.S. natural gas consumption - Gas Week: (10/6/22 - 10/12/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 68.0 |
65.9 |
63.0 |
| Power | 31.1 |
29.7 |
32.7 |
| Industrial | 22.6 |
22.6 |
21.5 |
| Residential/commercial | 14.4 |
13.6 |
8.8 |
| Mexico exports | 5.8 |
5.8 |
5.9 |
| Pipeline fuel use/losses | 6.7 |
6.6 |
6.3 |
| LNG pipeline receipts | 10.8 |
11.3 |
10.0 |
| Total demand | 91.3 |
89.7 |
85.2 |
|
Data source: PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, October 04, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 602 |
-0.3% |
39.0% |
| Natural gas rigs | 158 |
-0.6% |
59.6% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, October 04, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 23 |
0.0% |
-17.9% |
| Horizontal | 698 |
0.3% |
44.5% |
| Directional | 41 |
-10.9% |
86.4% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2022-10-07 |
2022-09-30 |
change |
|
| East | 782 |
756 |
26 |
|
| Midwest | 952 |
916 |
36 |
|
| Mountain | 190 |
184 |
6 |
|
| Pacific | 249 |
247 |
2 |
|
| South Central | 1,058 |
1,003 |
55 |
|
| Total | 3,231 |
3,106 |
125 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (10/7/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 831 |
-5.9 |
856 |
-8.6 |
|
| Midwest | 993 |
-4.1 |
1,001 |
-4.9 |
|
| Mountain | 209 |
-9.1 |
211 |
-10.0 |
|
| Pacific | 251 |
-0.8 |
289 |
-13.8 |
|
| South Central | 1,075 |
-1.6 |
1,096 |
-3.5 |
|
| Total | 3,357 |
-3.8 |
3,452 |
-6.4 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Oct 06) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 81 |
10 |
27 |
0 |
0 |
0 |
||
| Middle Atlantic | 80 |
21 |
51 |
0 |
-3 |
-2 |
||
| E N Central | 66 |
3 |
51 |
0 |
-4 |
-16 |
||
| W N Central | 40 |
-21 |
21 |
1 |
-6 |
-11 |
||
| South Atlantic | 49 |
21 |
43 |
19 |
-21 |
-37 |
||
| E S Central | 39 |
12 |
37 |
2 |
-22 |
-42 |
||
| W S Central | 9 |
3 |
8 |
35 |
-13 |
-31 |
||
| Mountain | 46 |
-17 |
-3 |
22 |
-1 |
7 |
||
| Pacific | 3 |
-17 |
-9 |
22 |
6 |
0 |
||
| United States | 45 |
1 |
28 |
12 |
-8 |
-16 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Oct 06, 2022
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Oct 06, 2022
Data source: National Oceanic and Atmospheric Administration
