In the News:
Henry Hub prices remain higher than Northeast hubs
The U.S. benchmark natural gas spot price at the Henry Hub in Louisiana remains at a premium to Northeast natural gas hubs. The premium increased in the third quarter of 2020, as total Appalachian supply exceeded demand growth and storage levels were above average. Although storage levels fell in 2021, other factors, such as record high Gulf Coast LNG exports, winter freeze-offs in Texas and neighboring producing areas, and Appalachian pipeline outages kept the Henry Hub price premium over Northeast hubs higher than 2018-2020 annual averages in 2021.
In 2020, total Appalachian supply and net imports together were 3% higher than 2019 levels, while Northeast demand remained low, partly as industrial and commercial activity fell following the onset of the COVID-19 pandemic. The natural gas that is not consumed in the region or exported out of the region is injected into storage. The East storage region has about 1 trillion cubic feet of storage capacity to balance seasonal demand against supply. In the first week of September 2020, before the winter withdrawal season started, storage levels were 6% above the five-year average, at 803 billion cubic feet (Bcf). With production growth continuing throughout winter of 2020, and demand remaining muted, natural gas in storage in the East reached near weekly 2016-2020 five-year highs.
While total Appalachian supply and net imports keeps rising, natural gas demand has recently increased as well. Total Appalachian supply and net imports grew by 6% to 30.8 Bcf/d during the first half of 2021, compared to same time last year. This year’s first half demand totaled 20.9 Bcf/d, or 0.8 Bcf/d higher than last year’s first half values, according to demand data from IHS Markit.
With rising demand, storage levels have fallen below their five-year average and Appalachian prices have risen. For the first eight months of 2021, prices in the Eastern Gas South averaged $2.60 per million British thermal units (MMBtu), or $1.18/MMBtu higher than the same period last year. Other Northeast hubs followed similar trends.
Henry Hub prices have also increased in 2021, and consequently still trades at a premium to Northeast hubs. Several factors contributed to this Henry Hub premium. In 2021, record LNG exports out of U.S. terminals located around the Gulf Coast increased South region demand. This February’s winter-freeze disproportionately increased prices in the South Central and Southeast, where processing facilities are not as well winterized as those in the Northeast. In addition, recent pipeline outages reduced southbound capacity out of the Appalachia basin.
Although pipeline capacity out of Appalachia has grown, it has not kept pace with recent production growth. The 2.0 Bcf/d Mountain Valley Pipeline is scheduled to come online in 2022, but it is mostly an intra-region and may not affect basis differentials substantially.
Overview:
(For the week ending Wednesday, September 22, 2021)
- U.S. natural gas spot prices fell at most locations this report week (Wednesday, September 15 to Wednesday, September 22). The Henry Hub spot price fell from $5.60 per million British thermal units (MMBtu) last Wednesday to $4.83/MMBtu yesterday.
- International natural gas prices continue to rise. Bloomberg Finance, L.P. reports swap prices for October liquefied natural gas (LNG) cargos in East Asia rose to a weekly average of $23.98/MMBtu this report week, the highest weekly average on record going back to January 2020 and $5.29/MMBtu above last week’s average of $18.69/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid European natural gas spot market, prices averaged $19.86/MMBtu this report week, the highest weekly average on record going back to September 2007 and up $1.90/MMBtu from last week’s average of $17.96/MMBtu. In the same week last year (week ending Sep. 23, 2020), prices in East Asia and at TTF were at $4.76/MMBtu and $3.30/MMBtu, respectively.
- The price of the October 2021 NYMEX contract decreased 66¢, from $5.460/MMBtu last Wednesday to $4.805/MMBtu yesterday. The price of the 12-month strip averaging October 2021 through September 2022 futures contracts declined 41¢/MMBtu to $4.258/MMBtu. Natural gas futures prices have receded from last week’s multi-year highs, with only the January futures contract settling yesterday above $5.00/MMBtu, at $5.04/MMBtu.
- The net injections to working gas totaled 76 billion cubic feet (Bcf) for the week ending September 17. Working natural gas stocks totaled 3,082 Bcf, which is 16% lower than the year-ago level and 7% lower than the five-year (2016–2020) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 47¢/MMBtu, averaging $11.17/MMBtu for the week ending September 22. Natural gas prices at the Houston Ship Channel fell 3%, and ethane prices fell 1%, widening the ethane premium to natural gas for the third consecutive week, which increased by 13%. Brent crude oil prices rose 2%, which was less than the price increases of normal butane, isobutane, and natural gasoline, which rose 4%, 5%, and 3%, respectively. Elevated exports of normal butane have put upward pressure on butane prices. For the third consecutive week, in the week ending September 22, the propane premium to crude oil widened, increasing by 59%, or 67¢/MMBtu, to $1.80/MMBtu above crude oil’s heating value equivalent. Propane prices rose 8%, reflecting strong international demand and rising domestic consumption due to cooling weather and the restart of Flint Hills’ propane dehydrogenation (PDH) unit in Houston, Texas, which consumes approximately 30,000 barrels per day (b/d) of propane for propylene production. Every Wednesday starting after the first Monday in October through the Wednesday after the last Monday in March, we release our Propane Market Update on the Winter Heating Fuels page, which includes retail prices and market analysis related to the winter heating season.
- According to Baker Hughes, for the week ending Tuesday, September 14, the natural gas rig count decreased by 1 to 100 as a result of a one-rig loss in the Haynesville. The number of oil-directed rigs rose by 10 to 411, led by the Permian Basin, which gained 5 rigs: 2 in New Mexico and 3 in Texas. At 259, the Permian Basin rig count is now at the highest level since mid-April of last year. The total rig count increased by 9, and it now stands at 512.
Prices/Supply/Demand:
Prices in the Gulf Coast region decline this week on improved supply/demand fundamentals. This report week (Wednesday, September 15, to Wednesday, September 22), the Henry Hub spot price fell 77¢ from $5.60/MMBtu last Wednesday to $4.83/MMBtu yesterday. Prices at Katy, a major storage and pipeline hub outside of Houston, fell 67¢ from $5.49/MMBtu last Wednesday to $4.76/MMBtu yesterday. The Bureau of Safety and Environmental Enforcement (BSEE) reported more production from the offshore Gulf of Mexico returning. The BSEE estimates impaired offshore natural gas production due to Hurricane Ida was at 540 million cubic feet per day (MMcf/d) yesterday, down 340 MMcf/d from 880 MMcf/d last Wednesday. Demand in the Gulf Coast region has also declined week over week. Natural gas deliveries of feed gas to liquefied natural gas (LNG) terminals dropped week over week by an average 110 MMcf/d in Texas and a further 240 MMcf/d in Southern Louisiana. The passing of Hurricane Nicholas through the Gulf Coast region, and its landfall near Freeport, Texas, on September 14, disrupted shipping activities at numerous ports along the coast and caused a power outage in the Houston area that resulted in the Freeport LNG Terminal shutting down. IHS Markit reports feed gas volumes to Freeport dropped from full capacity, at more than 1.3 billion cubic feet per day (Bcf/d) before the hurricane’s landfall, to close to zero from September 14 through September 17. Deliveries resumed on September 18 at approximately 2/3 of normal volumes, and rebounded to full capacity from September 21 onwards.
Midwest prices decline with lower demand, stronger natural gas inventory builds. At the Chicago Citygate, the price decreased 84¢ from a weekly high of $5.49/MMBtu last Wednesday to a weekly low of $4.65/MMBtu yesterday. Temperatures across the region are transitioning from cooling to heating demand. In the Chicago Area, the daily high temperature on Friday reached 89°F, 14°F above normal, resulting in 12 cooling degree days (CDD) for the day. Yesterday, temperatures reached a daily high of 63°F, 10°F below normal, resulting in 5 heating degree days (HDD). The shift in temperatures led to declining natural gas consumption for electricity generation in the Midwest from more than 3.0 Bcf/d on Friday to less than 1.9 Bcf/d yesterday. Natural gas demand in the residential and commercial sector rose from less than 1.5 Bcf/d on Friday to more than 2.8 Bcf/d yesterday, according to estimates from IHS Markit. Higher inflows of natural gas into the Midwest, estimated by IHS Markit to have increased by an average of 0.5 Bcf/d above last week’s average, supported supply growth, which has allowed inventories to build. We report stocks in the Midwest rising 28 Bcf for the week ending September 17, compared with a draw of 10 Bcf in the same week last year and a five-year average draw of 2.6 Bcf.
Prices in California decline, reflecting generally lower natural gas prices across the country and lower demand week on week. The price at PG&E Citygate in Northern California fell 71¢, down from $7.43/MMBtu last Wednesday to a weekly low of $6.72/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, fell 58¢ from $5.63/MMBtu last Wednesday to $5.05/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased $1.64 from $8.03/MMBtu last Wednesday to $6.39/MMBtu yesterday after reaching a weekly high of $8.83/MMBtu on Monday. According to data from IHS Markit, electric power sector consumption of natural gas in the West decreased 1.1 Bcf/d, or 18%, this week. Average temperatures in downtown Los Angeles, California, were below normal for most of the report week, averaging 67°F Thursday, September 16 through Sunday, September 19, decreasing cooling demand. On Tuesday, September 21, average temperatures in downtown Los Angeles increased 6°F, or 6°F above normal.
Moderate temperatures and lower pipeline deliveries to the Cove Point LNG export terminal lead to lower prices in the Northeast. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.06 from $5.45/MMBtu last Wednesday to $4.39/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased $1.01 from $5.23/MMBtu last Wednesday to $4.22/MMBtu yesterday. BHE GT&S, operator of the Cove Point LNG export terminal, announced that maintenance at the facility would start September 20 (notice ID 124379). BHE GT&S reports only 2 MMcf/d of scheduled volumes of natural gas for delivery to Cove Point starting on September 20, down from a steady flow of 756 MMcf/d of feedgas before the shutdown. Maintenance at Cove Point typically takes place beginning in September every year and has historically lasted a little more than three weeks.
Prices in the Appalachia production region decrease along with declining net outflows of natural gas. The Tennessee Zone 4 Marcellus spot price decreased 99¢ from $5.01/MMBtu last Wednesday to $4.02/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell $1.09 from $5.07/MMBtu last Wednesday to $3.98/MMBtu yesterday. Net flows of natural gas from the Appalachia region to the Southern Corridor decreased 0.5 Bcf/d this week, according to data from IHS Markit, as production in the Federal Offshore Gulf of Mexico (GOM) continues to come back online following supply shut-ins caused by Hurricane Ida (see Supply section below). Net flows of natural gas from the Appalachia region to the Atlantic region also decreased this week by 0.3 Bcf/d, partially as a result of the start of annual maintenance at the Cove Point LNG facility in Maryland (see Northeast region above).
Prices in the Permian Basin production region decline in line with price declines on the Gulf Coast. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, fell 77¢/MMBtu this report week, from $5.29/MMBtu last Wednesday to $4.52/MMBtu yesterday, matching the decline in the spot price at the Henry Hub in Louisiana. The Waha Hub traded 31¢/MMBtu below the Henry Hub price yesterday, on par with last Wednesday when it also traded 31¢/MMBtu below the Henry Hub price.
U.S. supply of natural gas increases slightly as Gulf of Mexico production continues to come back online. According to data from IHS Markit, the average total supply of natural gas rose by 0.2% compared with the previous report week. Dry natural gas production grew by 0.3% compared with the previous report week. Natural gas production in the Gulf of Mexico continues to come back online after being almost completely shut-in (over 90%) following Hurricane Ida. According to the BSEE, 0.5 Bcf (24%) of natural gas production remains shut-in as of yesterday. The remaining shut-in volume as of yesterday is 0.3 Bcf less than at the end of last report week, Wednesday, September 15. Average net imports from Canada decreased by 0.2% from last week.
U.S. consumption declines, driven by lower electric power sector demand. Total U.S. consumption of natural gas fell by 0.7% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 3.1%, or 1.1 Bcf/d, week over week as temperatures moderated this week compared with last week, especially in the Northwest. Industrial sector consumption increased by 1.0% week over week. In the residential and commercial sectors, consumption increased by 5.1%, or 0.4 Bcf/d to 8.8 Bcf/d. Residential and commercial sector demand was 15.2% less this report week than it was for the same week last year. Natural gas exports to Mexico increased 3.5% week over week. Natural gas deliveries to LNG export facilities (LNG pipeline receipts) averaged 9.8 Bcf/d, or 0.62 Bcf/d lower than last week.
U.S. LNG exports increase week over week. Twenty one LNG vessels (nine from Sabine Pass, five from Corpus Christi, four from Cameron, and one each from Cove Point, Elba Island, and one from Freeport, which typically loads three or four vessels per week) with a combined LNG-carrying capacity of 76 Bcf departed the United States between September 16 and September 22, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 76 Bcf for the week ending September 17, compared with the five-year (2016–2020) average net injections of 74 Bcf and last year's net injections of 70 Bcf during the same week. Working natural gas stocks totaled 3,082 Bcf, which is 229 Bcf lower than the five-year average and 589 Bcf 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 53 Bcf to 83 Bcf, with a median estimate of 74 Bcf.
The average rate of injections into storage is 13% 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 9.3 Bcf/d for the remainder of the refill season, the total inventory would be 3,490 Bcf on October 31, which is 229 Bcf lower than the five-year average of 3,719 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, 16-Sep |
Fri, 17-Sep |
Mon, 20-Sep |
Tue, 21-Sep |
Wed, 22-Sep |
|---|---|---|---|---|---|
| Henry Hub |
5.47 |
5.20 |
5.16 |
4.87 |
4.83 |
| New York |
5.05 |
4.93 |
4.35 |
3.96 |
4.22 |
| Chicago |
5.26 |
5.04 |
4.96 |
4.66 |
4.65 |
| Cal. Comp. Avg.* |
6.38 |
6.35 |
6.76 |
6.29 |
5.77 |
| Futures ($/MMBtu) | |||||
| October contract | 5.335 |
5.105 |
4.985 |
4.805 |
4.805 |
| November contract |
5.382 |
5.146 |
5.022 |
4.842 |
4.855 |
| *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: (9/16/21 - 9/22/21) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 104.1 |
103.8 |
100.1 |
| Dry production | 92.5 |
92.3 |
88.3 |
| Net Canada imports | 4.9 |
4.9 |
3.5 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 97.4 |
97.2 |
91.9 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (9/16/21 - 9/22/21) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 63.1 |
63.5 |
64.1 |
| Power | 33.0 |
34.1 |
31.8 |
| Industrial | 21.2 |
21.0 |
21.8 |
| Residential/commercial | 8.8 |
8.4 |
10.4 |
| Mexico exports | 5.7 |
5.5 |
6.0 |
| Pipeline fuel use/losses | 6.2 |
6.2 |
6.0 |
| LNG pipeline receipts | 9.8 |
10.4 |
6.8 |
| Total demand | 84.8 |
85.6 |
82.9 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, September 14, 2021 |
Change from |
||
last week |
last year |
||
| Oil rigs | 411 |
2.5% |
129.6% |
| Natural gas rigs | 100 |
-1.0% |
37.0% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, September 14, 2021 |
Change from |
||
last week |
last year |
||
| Vertical | 29 |
11.5% |
70.6% |
| Horizontal | 466 |
1.1% |
116.7% |
| Directional | 17 |
6.3% |
-26.1% |
| Source: Chart by the U.S. Energy Information Administration (EIA), based on data from Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2021-09-17 |
2021-09-10 |
change |
|
| East | 751 |
732 |
19 |
|
| Midwest | 904 |
876 |
28 |
|
| Mountain | 196 |
193 |
3 |
|
| Pacific | 240 |
240 |
0 |
|
| South Central | 990 |
965 |
25 |
|
| Total | 3,082 |
3,006 |
76 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (9/17/20) |
5-year average (2016-2020) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 847 |
-11.3 |
807 |
-6.9 |
|
| Midwest | 1,005 |
-10.0 |
928 |
-2.6 |
|
| Mountain | 224 |
-12.5 |
206 |
-4.9 |
|
| Pacific | 312 |
-23.1 |
294 |
-18.4 |
|
| South Central | 1,282 |
-22.8 |
1,075 |
-7.9 |
|
| Total | 3,671 |
-16.0 |
3,311 |
-6.9 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Sep 16) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 7 |
-18 |
-17 |
19 |
14 |
3 |
||
| Middle Atlantic | 3 |
-14 |
-10 |
34 |
19 |
13 |
||
| E N Central | 8 |
-14 |
-18 |
34 |
18 |
22 |
||
| W N Central | 9 |
-19 |
-44 |
44 |
22 |
35 |
||
| South Atlantic | 1 |
-3 |
-2 |
73 |
9 |
-9 |
||
| E S Central | 2 |
-2 |
2 |
58 |
5 |
-24 |
||
| W S Central | 0 |
-2 |
-4 |
86 |
0 |
9 |
||
| Mountain | 5 |
-27 |
-39 |
62 |
20 |
32 |
||
| Pacific | 5 |
-5 |
3 |
44 |
12 |
8 |
||
| United States | 5 |
-11 |
-13 |
52 |
13 |
9 |
||
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from the National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Sep 16, 2021
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Sep 16, 2021
Source: National Oceanic and Atmospheric Administration
