In the News:
Natural gas consumption, production, and exports broke records in 2022 as real average prices hit 14-year high
EIA estimates U.S. natural gas consumption to reach record levels in 2022 partly because of increased natural gas use in the electric power sector, according to our January Short-Term Energy Outlook (STEO). We estimate that domestic natural gas consumption averaged 88.7 billion cubic feet per day (Bcf/d) in 2022, a 6% increase from 2021. Electric power sector consumption averaged 33.3 Bcf/d, an all-time high and up 8% from 2021, as the third-hottest summer on record boosted July air-conditioning demand. Although natural gas prices were high compared with the previous five years, coal supply constraints, relatively high coal prices, and below-average stockpiles at coal-burning power plants contributed to less coal-fired power generation and more natural gas-fired power generation. Primarily affected by changes in temperature, total natural gas consumption rose in the residential sector (5%) and the commercial sector (7%).
U.S. natural gas production reached a record high in 2022 as a result of:
- Continued decline in drilled but uncompleted wells
- Higher rig counts surpassing March 2020 levels
- Increased takeaway capacity to supply Gulf Coast liquefied natural gas (LNG) terminals
Dry natural gas production averaged 98.0 Bcf/d in 2022, surpassing the 2021 all-time high by 3.5 Bcf/d. The Permian and Haynesville regions led the increase in production.
U.S. natural gas storage inventories were historically low for much of 2022, as temperature-related demand increases outpaced production growth. Lower-than-normal temperatures during the 2021–22 heating season (November 2021–March 2022) pushed U.S. natural gas inventories to a three-year low of 1,387 billion cubic feet (Bcf) on March 31, 17% below the five-year (2017–21) average. Net withdrawals rose to a four-year high during the 2021–22 heating season. During the refill season (April 2022–October 2022), higher-than-normal summer temperatures contributed to below-average net injections into storage. However, mild temperatures combined with higher production led to above-average weekly injection volumes in September and October, resulting in storage inventories ending the refill season 3% below the year-ago and five-year averages.
The 2022 average wholesale U.S. natural gas spot price at the Henry Hub was the highest in real and nominal terms since 2008, averaging $6.45 per million British thermal units (MMBtu), according to data from Refinitiv Eikon. Daily prices reached a high of $9.85/MMBtu on August 22 and a low of $3.46/MMBtu on November 9, and exhibited volatility throughout the year. Regional prices in the Northeast spiked in January, while regional prices throughout the western United States reached over $50.00/MMBtu in December and prices at the Waha Hub in West Texas traded below the Henry Hub for most of the year.
U.S. gross natural gas exports continued their upward trend, as LNG capacity and exports in 2022 surpassed those in 2021 and drove total exports higher. The seventh U.S. LNG export terminal began operations in March, adding 1.3 Bcf/d in baseload LNG production capacity, which helped offset some of the 2 Bcf/d of capacity lost from a shutdown of the Freeport LNG terminal in June. Expanded pipeline infrastructure in producing regions supplying the U.S. Gulf Coast increased capacity to transport natural gas to nearby industrial facilities and LNG terminals, allowing U.S. shippers to grow exports. More than 60% of U.S. LNG exports continued to flow to European Union destinations in the first 10 months of 2022, displacing East Asian markets as the top destination for U.S. LNG, mainly to offset a decline in Russia’s natural gas pipeline exports to Europe.
Market Highlights:
(For the week ending Wednesday, January 11, 2023)Prices
- Henry Hub spot price: The Henry Hub spot price fell 46 cents from $3.81 per million British thermal units (MMBtu) last Wednesday to $3.35/MMBtu yesterday.
- Henry Hub futures prices: The price of the February 2023 NYMEX contract decreased 50.1 cents, from $4.172/MMBtu last Wednesday to $3.671/MMBtu yesterday. The price of the 12-month strip averaging February 2023 through January 2024 futures contracts declined 34.8 cents to $3.748/MMBtu.
- Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, January 4, to Wednesday, January 11). Week-over-week price changes at major pricing hubs ranged from a decrease of $2.02/MMBtu at SoCal Citygate to a decrease of $0.06/MMBtu at the Waha Hub. Only the PG&E Citygate price increased, by $0.11/MMBtu week over week.
- Prices in the West mostly fell this report week and have come off the highs seen in mid-December but remain at a premium relative to Henry Hub and other major U.S. markets. The price at Sumas on the Canada-Washington border, the main pricing point for the Pacific Northwest, fell $1.84 from $11.50/MMBtu last Wednesday to $9.66/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, fell $1.47 from $17.54/MMBtu last Wednesday to $16.07/MMBtu yesterday. The price at SoCal Citygate in Southern California decreased $2.02 from $20.18/MMBtu last Wednesday to $18.16/MMBtu yesterday. Above-normal temperatures returned to the West this week, even as a powerful mid-latitude cyclone affected the Pacific Coast, bringing heavy rain and snow. In the Seattle City Area temperatures averaged 47°F this week, 5°F above normal, which resulted in 40 fewer heating degree days (HDDs) than normal. Temperatures in the Sacramento Area averaged 53°F this week, which resulted in 40 fewer HDDs than normal. In Southern California, temperatures started to fall yesterday, but for the week, temperatures in the Riverside Area averaged 54°F, slightly higher than last week. Total consumption of natural gas in the Western region decreased by 2%, or 0.3 billion cubic feet per day (Bcf/d), week over week, according to data from PointLogic.
- The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, remains the lowest among major pricing hubs. The price fell 6 cents this report week, from $1.78/MMBtu last Wednesday to $1.72/MMBtu yesterday. The Waha Hub traded $1.63 below the Henry Hub price yesterday, compared with last Wednesday when it traded $2.03 below the Henry Hub price.
- In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price decreased 66 cents from $4.04/MMBtu last Wednesday to $3.38/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 56 cents from $3.35/MMBtu last Wednesday to $2.79/MMBtu yesterday. The Tennessee Zone 4 Marcellus spot price decreased 31 cents from $2.81/MMBtu last Wednesday to $2.50/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania fell 39 cents from $2.87/MMBtu last Wednesday to $2.48/MMBtu yesterday. Above-normal temperatures persist across the Northeast, although they have been falling in recent days. In the Boston Area this week, temperatures averaged 35°F, 4°F higher than normal, resulting in 31 fewer HDDs than normal. In the New York-Central Park Area, temperatures averaged 41°F this week, 7°F higher than normal, resulting in 48 fewer HDDs than normal.
- In the Midwest, at the Chicago Citygate, the price decreased 28 cents from $3.43/MMBtu last Wednesday to $3.15/MMBtu yesterday, as temperatures increased from earlier this week. Temperatures in the Chicago Area averaged 30°F on Sunday and increased to 48°F yesterday. For the report week, temperatures in the Chicago Area averaged 35°F, 9°F higher than normal and 6°F lower than last week. Total natural gas consumption in the Midwest increased 26% (3.6 Bcf/d) week over week, driven by large increases in demand in the residential, commercial, and electric power sectors, according to data from PointLogic.
- International futures prices: International natural gas futures prices decreased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased $1.63 to a weekly average of $27.67/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased $1.17 to a weekly average of $22.02/MMBtu. In the same week last year (week ending January 12, 2022), the prices in East Asia and at TTF were $33.44/MMBtu and $28.18/MMBtu, respectively.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 6 cents/MMBtu, averaging $7.66/MMBtu for the week ending January 11. Ethane prices fell 7%, while average weekly natural gas prices at the Houston Ship Channel rose 7% week over week, narrowing the ethane premium to natural gas by 29%. Ethylene spot prices rose 4%, widening the ethylene to ethane premium by 16%. Propane prices rose 3%, while the weekly average price of Brent crude oil fell 2%, resulting in an 8% decrease in the propane discount relative to crude oil. Normal butane and natural gasoline prices rose 3%, and isobutane prices rose 5%.
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 rose by 2.2% (2.3 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.9% (0.9 Bcf/d), and average net imports from Canada increased by 30.9% (1.3 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas rose by 14.3% (11.6 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation climbed by 9.3% (2.6 Bcf/d) week over week. Industrial sector consumption increased by 4.0% (1.0 Bcf/d), and in the residential and commercial sectors, consumption increased by 27.3% (8.0 Bcf/d). Natural gas exports to Mexico increased 10.7% (0.5 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.3 Bcf/d, or 0.7 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Overall natural gas deliveries to U.S. LNG export terminals increased by 0.7 Bcf/d week over week to average 12.3 Bcf/d this report week, according to data from PointLogic. Natural gas deliveries to LNG export terminals in South Louisiana increased by 0.6 Bcf/d to 8.7 Bcf/d, while natural gas deliveries to all other terminals increased by 0.1 Bcf/d week over week to 3.6 Bcf/d.
- Vessels departing U.S. ports: Twenty-four LNG vessels (eleven from Sabine Pass, four each from Cameron and Corpus Christi, two each from Calcasieu Pass and Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 90 Bcf departed the United States between January 5 and January 11, according to shipping data provided by Bloomberg Finance, L.P.
- Vessels arriving at U.S. ports: One LNG vessel with a carrying capacity of 3 Bcf docked for off-loading at the Everett LNG terminal in Boston Harbor in Massachusetts between January 5 and January 11, according to shipping data provided by Bloomberg Finance, L.P. This delivery is the third to the terminal since November 2022.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, January 3, the natural gas rig count decreased by 4 to 152 rigs. Natural gas-directed rigs have been gradually declining from a high of 166 rigs in early September 2022, with week-over-week declines in 10 of the last 17 weeks. In the latest report, one natural gas-directed rig was added in the Utica, three were dropped in the Haynesville, and one each was dropped in the Marcellus and an unidentified basin. The number of oil-directed rigs fell by 3 to 618 rigs. Two oil-directed rigs were added in the Granite Wash, and one was added in the Mississippian. One was dropped from the Arkoma Woodford, and five were dropped from unidentified basins. The total rig count, which includes 2 miscellaneous rigs, decreased by 7, and now stands at 772 rigs.
Storage
- The net injections into storage totaled 11 Bcf for the week ending January 6, compared with the five-year (2018–2022) average net withdrawals of 157 Bcf and last year's net withdrawals of 157 Bcf during the same week. Working natural gas stocks totaled 2,902 Bcf, which is 40 Bcf (1%) lower than the five-year average and 140 Bcf (5%) 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 withdrawals of 35 Bcf to net injections of 16 Bcf, with a median estimate of net withdrawals of 3 Bcf.
- The average rate of withdrawals from storage is 10% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 16.8 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,492 Bcf on March 31, which is 40 Bcf lower than the five-year average of 1,532 Bcf for that time of year.
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Data source: U.S. Energy Information Administration, Short-Term Energy Outlook
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook
| Spot Prices ($/MMBtu) | Thu, 5 Jan |
Fri, 6-Jan |
Mon, 9-Jan |
Tue, 10-Jan |
Wed, 11-Jan |
|---|---|---|---|---|---|
| Henry Hub | 3.76 | 3.42 | 3.67 | 3.32 | 3.35 |
| New York | 3.17 | 3.50 | 3.98 | 3.37 | 2.79 |
| Chicago | 3.38 | 3.25 | 3.44 | 3.10 | 3.15 |
| Cal. Comp. Avg,* | 16.55 | 17.09 | 18.42 | 18.76 | 17.63 |
| Futures ($/MMBtu) | |||||
| February Contract | 3.720 | 3.710 | 3.910 | 3.639 | 3.671 |
| March Contract | 3.426 | 3.392 | 3.563 | 3.314 | 3.346 |
| Data source: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. | |||||
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Spot Prices ($/MMBtu) | Thu, 29-Dec |
Fri, 30-Dec |
Mon, 2-Jan |
Tue, 3-Jan |
Wed, 4-Jan |
|---|---|---|---|---|---|
| Henry Hub | 3.70 | 3.55 | Holiday | 3.65 | 3.81 |
| New York | 3.29 | 2.77 | Holiday | 2.56 | 3.35 |
| Chicago | 3.49 | 3.41 | Holiday | 3.34 | 3.43 |
| Cal. Comp. Avg,* | 15.00 | 15.31 | Holiday | 23.66 | 18.37 |
| Futures ($/MMBtu) | |||||
| February Contract | 4.559 | 4.475 | Holiday | 3.988 | 4.172 |
| March Contract | 4.117 | 4.104 | Holiday | 3.641 | 3.780 |
| Data source: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. | |||||
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Spot Prices ($/MMBtu) | Thu, 22-Dec |
Fri, 23-Dec |
Mon, 26-Dec |
Tue, 27-Dec |
Wed, 28-Dec |
|---|---|---|---|---|---|
| Henry Hub | 7.30 | 6.56 | Holiday | 4.90 | 4.12 |
| New York | 32.12 | 35.61 | Holiday | 6.29 | 5.15 |
| Chicago | 11.62 | 8.35 | Holiday | 4.84 | 3.92 |
| Cal. Comp. Avg,* | 32.16 | 36.93 | Holiday | 26.78 | 20.86 |
| Futures ($/MMBtu) | |||||
| January Contract | 4.999 | 5.079 | Holiday | 5.282 | 4.709 |
| February Contract | 4.928 | 4.980 | Holiday | 5.118 | 4.685 |
| 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: (1/5/23 - 1/11/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 112.6 |
111.7 |
105.9 |
| Dry production | 100.2 |
99.2 |
94.4 |
| Net Canada imports | 5.5 |
4.2 |
6.1 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.2 |
| Total supply | 105.8 |
103.5 |
100.7 |
|
Data source: PointLogic | |||
| U.S. natural gas consumption - Gas Week: (1/5/23 - 1/11/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 93.1 |
81.5 |
105.6 |
| Power | 30.7 |
28.1 |
30.7 |
| Industrial | 24.8 |
23.8 |
26.3 |
| Residential/commercial | 37.5 |
29.5 |
48.6 |
| Mexico exports | 5.4 |
4.9 |
5.7 |
| Pipeline fuel use/losses | 7.4 |
7.1 |
7.6 |
| LNG pipeline receipts | 12.3 |
11.7 |
12.1 |
| Total demand | 118.3 |
105.1 |
131.0 |
|
Data source: PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, January 03, 2023 |
Change from |
||
last week |
last year |
||
| Oil rigs | 618 |
-0.5% |
28.5% |
| Natural gas rigs | 152 |
-2.6% |
42.1% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, January 03, 2023 |
Change from |
||
last week |
last year |
||
| Vertical | 26 |
-3.7% |
13.0% |
| Horizontal | 700 |
-0.8% |
31.6% |
| Directional | 46 |
0.0% |
39.4% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2023-01-06 |
2022-12-30 |
change |
|
| East | 700 |
691 |
9 |
|
| Midwest | 823 |
839 |
-16 |
|
| Mountain | 153 |
157 |
-4 |
|
| Pacific | 160 |
165 |
-5 |
|
| South Central | 1,067 |
1,040 |
27 |
|
| Total | 2,902 |
2,891 |
11 |
|
| 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 (1/6/22) |
5-year average (2018-2022) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 735 |
-4.8 |
702 |
-0.3 |
|
| Midwest | 843 |
-2.4 |
826 |
-0.4 |
|
| Mountain | 161 |
-5.0 |
162 |
-5.6 |
|
| Pacific | 206 |
-22.3 |
235 |
-31.9 |
|
| South Central | 1,096 |
-2.6 |
1,017 |
4.9 |
|
| Total | 3,042 |
-4.6 |
2,942 |
-1.4 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jan 05) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 165 |
-101 |
-38 |
0 |
0 |
0 |
||
| Middle Atlantic | 134 |
-120 |
-51 |
0 |
0 |
0 |
||
| E N Central | 168 |
-121 |
-82 |
0 |
0 |
0 |
||
| W N Central | 229 |
-84 |
-114 |
0 |
0 |
0 |
||
| South Atlantic | 75 |
-105 |
-27 |
13 |
6 |
-2 |
||
| E S Central | 63 |
-123 |
-49 |
1 |
0 |
-5 |
||
| W S Central | 59 |
-80 |
-45 |
8 |
6 |
-5 |
||
| Mountain | 227 |
-9 |
-32 |
0 |
0 |
0 |
||
| Pacific | 128 |
2 |
-21 |
0 |
0 |
0 |
||
| United States | 140 |
-82 |
-54 |
3 |
1 |
-1 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Jan 05, 2023
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Jan 05, 2023
Data source: National Oceanic and Atmospheric Administration
