In the News:
Calcasieu Pass, the seventh LNG export terminal in the Lower 48 states, begins production
Since November 2021, Venture Global Calcasieu Pass, LLC, (Venture Global)―the developer of the Calcasieu Pass liquefied natural gas (LNG) export terminal―has received Federal Energy Regulatory Commission (FERC) approvals to commission the first six of nine liquefaction blocks. FERC issued the most recent approval on March 30, 2022. Each block contains two mid-scale liquefaction units called trains. The first authorization, issued in November 2021, was one of the initial steps toward full commercial service, and Calcasieu Pass could reach its full LNG production capacity of 1.3 billion cubic feet per day (Bcf/d) baseload (1.6 Bcf/d peak) by the fourth quarter of this year. Natural gas deliveries to the terminal have increased throughout 2022, averaging approximately 0.8 Bcf/d in April, according to PointLogic.
Calcasieu Pass is a greenfield liquefaction facility, located in Cameron Parish, Louisiana. As in nearby LNG terminals Sabine Pass and Cameron, LNG tankers loaded at Calcasieu Pass reach the Gulf of Mexico through the Calcasieu Ship Channel. Calcasieu Pass is the seventh U.S. LNG liquefaction export facility to begin producing LNG since Cheniere’s Sabine Pass began production in 2016.
Calcasieu Pass uses a modular technology, which includes mid-scale refrigeration trains, allowing for a shorter project construction timeline. As a result, Calcasieu Pass produced its first LNG 30 months (two and a half years) after Venture Global made the final investment decision (FID), which was the shortest amount of time between FID and first LNG production of all the LNG export projects in the United States. In comparison, the development timeline from FID to first LNG production for other U.S. LNG export projects ranged from three and a half to five and a half years.
In addition to 18 mid-scale liquefaction trains, the Calcasieu Pass facility includes an onsite natural gas-fired combined-cycle turbine to generate electricity for the facility’s operations, three pre-treatment trains, and two LNG storage tanks (each with a capacity equivalent to 4.4 Bcf of gasified natural gas). The facility has two ship berths and is capable of loading LNG vessels with carrying capacities of up to 185,000 cubic meters (4.1 Bcf). The Calcasieu Pass terminal receives its feed gas through Venture Global’s 24-mile, 42-inch diameter TransCameron Pipeline, which has interconnections with the ANR, Texas Eastern Transmission Company (TETCO), and Bridgeline pipelines.
Calcasieu Pass has entered into multiple long-term sales and purchase agreements with several buyers for the total output from the terminal. We estimate that at least 0.5 Bcf/d of LNG contracted by European-based companies are likely to be delivered to Europe. Chinese energy companies have committed to purchasing about 0.3 Bcf/d, and the remaining volumes have been contracted to companies with large portfolios of LNG supply and delivery contracts. The majority of the agreements have a 20-year term in which the LNG is sold on a free on board (FOB) basis, indexed to the monthly U.S. Henry Hub natural gas price plus a facility fee indexed to inflation.
On March 1, Calcasieu Pass loaded and shipped its first LNG cargo, often called a commissioning cargo, which delivered LNG to the Netherlands and France. As of May 4, Calcasieu Pass has shipped eleven cargoes, according to shipping data provided by Bloomberg Finance, L.P.
Overview:
(For the week ending Wednesday, May 4, 2022)
- Spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, April 27, to Wednesday, May 4). The Henry Hub spot price rose from $6.94 per million British thermal units (MMBtu) last Wednesday to $8.30/MMBtu yesterday. This price is the highest since a winter storm contributed to record-high spot prices in February 2021.
- International spot prices: International natural gas spot prices decreased this report week. Bloomberg Finance, L.P. reports that the swap prices for liquefied natural gas (LNG) cargoes in East Asia fell $1.46/MMBtu to a weekly average of $23.93/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead price decreased 11 cents to a weekly average of $30.84/MMBtu. The price at TTF averaged above the East Asia price for the third week in a row. Historically, the natural gas prices in East Asia average above natural gas prices in Europe. In the same week last year (week ending May 5, 2021), the prices in East Asia and at the TTF were $8.83/MMBtu and $8.35/MMBtu, respectively.
- Futures: The May 2022 NYMEX contract expired last Wednesday at $7.267/MMBtu. The June 2022 NYMEX contract price increased to $8.415/MMBtu, up $1.08 from last Wednesday to yesterday. The price of the 12-month strip averaging June 2022 through May 2023 futures contracts climbed 92 cents to $7.756/MMBtu.
- Storage: The net injections to working gas totaled 77 billion cubic feet (Bcf) for the week ending April 29. Working natural gas stocks totaled 1,567 Bcf, which is 20% lower than the year-ago level and 16% lower than the five-year (2017–2021) average for this week.
- NGPLs: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 57 cents/MMBtu, averaging $12.80/MMBtu for the week ending May 4. Ethane prices rose 12%, following the 12% increase in natural gas prices at the Houston Ship Channel. The price of ethylene increased by 3%, resulting in a narrower ethane to ethylene spread, which fell by 12%. The Brent crude oil price rose 3%, resulting in higher normal butane and isobutane prices, each of which rose 8%. The natural gasoline price rose 1%, and the propane price remained relatively unchanged, resulting in the propane discount to crude oil widening by 14%.
- Rigs: According to Baker Hughes, for the week ending Tuesday, April 26, the natural gas rig count was unchanged from a week ago at 144 rigs. The number of oil-directed rigs increased by 3 rigs to 552 rigs. The Eagle Ford, the Permian, the Williston, and an unspecified producing region each added one rig, and one rig was dropped in the Cana Woodford. The total rig count now stands at 698, the highest level since March 27, 2020, and 258 rigs more than the same week last year.
Prices/Supply/Demand:
Prices along the Gulf Coast rise with higher temperatures and increased demand for air conditioning. This report week (Wednesday, April 27 to Wednesday, May 4), the Henry Hub spot price rose $1.36 from $6.94 per million British thermal units (MMBtu) last Wednesday to $8.30/MMBtu yesterday. Prices in the South were all higher this report week. Higher temperatures across the region resulted in rising air-conditioning demand, leading to a 1.1 billion cubic feet per day (Bcf/d) (9%) increase in natural gas consumption in the electric power sector, according to data from PointLogic. Temperatures across the South were higher than normal this report week, particularly in South Texas. Temperatures in the Houston Area averaged 79°F, which is 5°F higher than normal. On Saturday, temperatures in the Houston Area reached a high of 89°F. Feed gas deliveries to liquefied natural gas (LNG) export terminals along the Gulf Coast decreased by 0.1 Bcf/d. Deliveries to terminals in South Texas increased by 0.5 Bcf/d (15%) but were more than offset by a decline in deliveries to terminals in South Louisiana, which fell by 0.6 Bcf/d (8%) as a result of a maintenance outage at the Cameron LNG terminal. Sempra, operator of Cameron LNG, reports that a scheduled three-week maintenance turnaround on Train 1 began on April 28. As a result, natural gas deliveries to the terminal averaged 1.4 Bcf/d this week, which is 0.7 Bcf/d less than a week ago. Cameron LNG plans to return Train 1 to operation on or around May 19.
Prices in the Midwest end the week higher but fluctuate with weather, while production from North Dakota continues to increase. At the Chicago Citygate, the price rose $1.21 from $7.01/MMBtu last Wednesday to $8.22/MMBtu yesterday. The Chicago Citygate price reached a weekly low of $6.63/MMBtu on Thursday before rising to a weekly high yesterday, fluctuating with weather. Temperatures in the Chicago Area averaged 51°F this report week, 4°F lower than normal, but were volatile throughout the week. Temperatures averaged 44°F at the beginning of the report week, which is 10°F lower than normal. Temperatures then increased to an average of 60°F on Saturday, 5°F higher than normal, but decreased again by Tuesday to an average of 47°F. Week over week, natural gas consumption in the Midwest increased slightly by 0.1 Bcf/d (1%), driven by an increase in consumption by the electric power sector. Natural gas production in the Plains region increased by 0.3 Bcf/d (22%) as a result of increasing production in North Dakota, where electricity and other utilities are being restored following last week’s unseasonal winter storm.
Prices across the West rise in line with the national average, and temperatures hover around normal. The price at PG&E Citygate in Northern California rose $1.52, from $7.97/MMBtu last Wednesday to $9.49/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, increased $1.30, from $6.93/MMBtu last Wednesday to $8.23/MMBtu yesterday. The price at Opal in southwest Wyoming (the main trading point for natural gas in the Rocky Mountain region and the origin point for deliveries into the California market through the Ruby Pipeline) rose $1.26, from $6.90/MMBtu last Wednesday to $8.16/MMBtu yesterday. The price at Sumas on the U.S.-Canada border in Washington State, the main pricing point for the Pacific Northwest, rose $1.10, from $6.83/MMBtu last Wednesday to $7.93/MMBtu yesterday. Temperatures in the Seattle City Area averaged 53°F this report week, which is normal for this time of year. Total natural gas consumption in the Pacific Northwest decreased by 0.2 Bcf/d (9%) this report week, according to data from PointLogic.
The price at SoCal Citygate in Southern California increased $1.35, up from $7.29/MMBtu last Wednesday to $8.64/MMBtu yesterday. Temperatures in the Riverside Area averaged 67°F this report week, 1°F higher than normal. Total natural gas consumption in California decreased by 0.2 Bcf/d (5%) this report week, according to data from PointLogic.
Prices in the Northeast are mixed this week. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.73 from $10.20/MMBtu last Wednesday to $8.47/MMBtu yesterday. The Algonquin Citygate price started the week at a higher level than other prices in the Northeast in anticipation of higher natural gas demand as a cold weather system moved into the region over the weekend. Since then, the price at Algonquin Citygate has fallen to a similar level to other pricing hubs. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 97 cents from $6.68/MMBtu last Wednesday to $7.65/MMBtu yesterday. Natural gas consumption in the Northeast increased by 0.1 Bcf/d (1%) week over week to an average of 15.7 Bcf/d, according to data from PointLogic. Consumption in the residential and commercial sectors and the industrial sector each rose this week by 2% to an average of 6.2 Bcf/d and 2.9 Bcf/d, respectively.
Prices in the Appalachian Basin fall at the start of the report week and then rise, in step with other pricing hubs. The Tennessee Zone 4 Marcellus spot price increased $1.07 from $6.43/MMBtu last Wednesday to $7.50/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose $1.09 from $6.43/MMBtu last Wednesday to $7.52/MMBtu yesterday. Pricing at both hubs fell to $5.95/MMBtu on Friday but then rose to result in a week-over-week increase. Natural gas production decreased by 0.2 Bcf/d (1%) this week to an average of 33.6 Bcf/d, according to data from PointLogic. Net natural gas flows out of the region increased by 0.5 Bcf/d (2%) to an average of 25.2 Bcf/d, led by a 5% increase in flows to the south to an average of 6.5 Bcf/d. The increase in southbound natural gas flows was offset somewhat by a decrease in flows to the Midwest of 0.2 Bcf/d (3%) to an average of 6.1 Bcf/d.
Prices in the Permian production region increase week over week but only after falling below $6/MMBtu on Monday, even as the Henry Hub price rose steadily. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose $1.29 this report week, from $6.49/MMBtu last Wednesday to $7.78/MMBtu yesterday. The Waha Hub traded 52 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 45 cents below the Henry Hub price. On Monday, the Waha Hub traded $1.81/MMBtu below the Henry Hub as the Waha Hub price fell to $5.49/MMBtu and the Henry Hub price rose. Natural gas flows out of the Permian Basin were mixed this week. Flows to the west and south decreased, reflecting lower demand in California and reduced exports to Mexico. Eastbound flows rose in response to higher feed gas flows to LNG export terminals in Texas and rising demand from the electric power sector (see Gulf Coast section above). Natural gas flows out of Texas in total decreased by 1.2 Bcf/d (12%) week over week to an average of 8.7 Bcf/d, according to data from PointLogic. Lower prices mid-report week and reduced natural gas flows out of the region are in part a result of ongoing pipeline maintenance, including by the Natural Gas Pipeline Company.
U.S. natural gas supply is essentially unchanged week over week. According to data from PointLogic, the average total supply of natural gas rose by 0.1% (0.1 Bcf/d) week over week. The small increase was the result of slightly higher domestic dry natural gas production, while average net imports from Canada were flat.
U.S. natural gas demand by sector is mixed this week. Total U.S. consumption of natural gas rose by 1.0% (0.6 Bcf/d) compared with the previous report week, led by a 3.9% (1.1 Bcf/d) increase in natural gas consumed for power generation. Industrial sector consumption of natural gas decreased by 0.7% (0.2 Bcf/d), and consumption in the residential and commercial sectors decreased by 1.6% (0.3 Bcf/d), according to data from PointLogic. Temperatures across the South were higher than normal this week, leading to increased demand for air conditioning. Temperatures in the West, Midwest, and Northeast were below normal during much of the week, leading to increased demand for heating in those regions. Natural gas exports to Mexico decreased 7.5% (0.5 Bcf/d) this report week, and natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 12.0 Bcf/d, 0.2 Bcf/d lower than the previous report week.
U.S. LNG exports increase by two vessels this week from last week. Twenty-five LNG vessels (nine from Sabine Pass, four from Corpus Christi, three each from Cameron and Freeport, and two each from Calcasieu Pass, Cove Point, and Elba Island) with a combined LNG-carrying capacity of 91 Bcf departed the United States between April 28 and May 4, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 77 Bcf for the week ending April 29, compared with the five-year (2017–2021) average net injections of 78 Bcf and last year's net injections of 53 Bcf during the same week. Working natural gas stocks totaled 1,567 Bcf, which is 306 Bcf lower than the five-year average and 382 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 56 Bcf to 81 Bcf, with a median estimate of 70 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, 28-Apr |
Fri, 29-Apr |
Mon, 02-May |
Tue, 03-May |
Wed, 04-May |
|---|---|---|---|---|---|
| Henry Hub |
6.79 |
6.84 |
7.30 |
7.86 |
8.30 |
| New York |
6.10 |
6.04 |
6.97 |
7.63 |
7.65 |
| Chicago |
6.63 |
6.76 |
7.37 |
7.99 |
8.22 |
| Cal. Comp. Avg.* |
6.95 |
6.98 |
7.53 |
8.35 |
8.75 |
| Futures ($/MMBtu) | |||||
| June contract | 6.888 |
7.244 |
7.475 |
7.954 |
8.415 |
| July contract |
6.994 |
7.355 |
7.566 |
8.025 |
8.472 |
|
Sources: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. |
|||||
| U.S. natural gas supply - Gas Week: (4/28/22 - 5/4/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 106.2 |
105.9 |
104.3 |
| Dry production | 94.2 |
94.1 |
92.2 |
| Net Canada imports | 6.0 |
6.0 |
4.3 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 100.3 |
100.2 |
96.5 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| U.S. natural gas consumption - Gas Week: (4/28/22 - 5/4/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 67.4 |
66.7 |
61.0 |
| Power | 27.8 |
26.7 |
27.1 |
| Industrial | 22.4 |
22.6 |
21.4 |
| Residential/commercial | 17.1 |
17.4 |
12.6 |
| Mexico exports | 5.6 |
6.1 |
6.0 |
| Pipeline fuel use/losses | 6.4 |
6.4 |
6.1 |
| LNG pipeline receipts | 12.0 |
12.2 |
11.2 |
| Total demand | 91.4 |
91.4 |
84.3 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, April 26, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 552 |
0.5% |
61.4% |
| Natural gas rigs | 144 |
0.0% |
50.0% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, April 26, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 25 |
0.0% |
31.6% |
| Horizontal | 643 |
0.6% |
61.6% |
| Directional | 30 |
-3.2% |
30.4% |
| 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 | 2022-04-29 |
2022-04-22 |
change |
|
| East | 253 |
238 |
15 |
|
| Midwest | 324 |
309 |
15 |
|
| Mountain | 92 |
90 |
2 |
|
| Pacific | 176 |
171 |
5 |
|
| South Central | 721 |
681 |
40 |
|
| Total | 1,567 |
1,490 |
77 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (4/29/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 330 |
-23.3 |
319 |
-20.7 |
|
| Midwest | 440 |
-26.4 |
401 |
-19.2 |
|
| Mountain | 123 |
-25.2 |
110 |
-16.4 |
|
| Pacific | 223 |
-21.1 |
205 |
-14.1 |
|
| South Central | 833 |
-13.4 |
838 |
-14.0 |
|
| Total | 1,949 |
-19.6 |
1,873 |
-16.3 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Apr 28) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 112 |
2 |
-1 |
0 |
0 |
0 |
||
| Middle Atlantic | 90 |
-2 |
-8 |
0 |
0 |
-1 |
||
| E N Central | 94 |
-2 |
-5 |
5 |
4 |
3 |
||
| W N Central | 100 |
14 |
0 |
4 |
1 |
1 |
||
| South Atlantic | 30 |
-12 |
-31 |
28 |
7 |
3 |
||
| E S Central | 26 |
-12 |
-29 |
19 |
11 |
10 |
||
| W S Central | 12 |
-2 |
-9 |
48 |
19 |
13 |
||
| Mountain | 91 |
-4 |
-7 |
9 |
-2 |
5 |
||
| Pacific | 59 |
3 |
-16 |
0 |
-4 |
0 |
||
| United States | 70 |
-1 |
-11 |
13 |
3 |
3 |
||
|
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 Apr 28, 2022
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Apr 28, 2022
Source: National Oceanic and Atmospheric Administration
