In the News:
U.S. associated natural gas production will likely grow through 2050
In our Annual Energy Outlook 2023 (AEO2023), natural gas produced from wells targeting crude oil, known as associated natural gas, generally grows across most cases through 2050, continuing a long-term trend. In the AEO2023 Reference case, associated natural gas accounts for approximately 20% of total U.S. natural gas production over the projection period. This share changes across cases, peaking in the High Oil Price case at 32% of natural gas production in 2030.
In our AEO2023, we explore long-term energy trends in the United States and present an outlook for energy markets through 2050. We use different scenarios, called cases, to understand how varying assumptions affect energy trends. The AEO2023 Reference case, which serves as a baseline, or benchmark, considers only the laws and regulations adopted through mid-November 2022, including the Inflation Reduction Act (IRA).
Historically, associated natural gas has been a relatively small proportion of U.S. natural gas supply. In 2010, associated natural gas production totaled 3.7 billion cubic feet per day (Bcf/d), accounting for about 6% of domestic production. By 2022, associated natural gas production had increased to 15.4 Bcf/d, or more than 15% of domestic natural gas production.
The Permian Basin (in the Southwest Census region) is the most productive U.S. oil-producing region and accounts for most of the associated natural gas produced in the United States today. In the AEO2023 Reference case, we project that associated natural gas production in the Southwest will continue to grow, from 12.1 Bcf/d in 2025 to 13.7 Bcf/d in 2050, accounting for over one-third of associated natural gas production growth in the United States over this period.
Our projected growth in associated natural gas production is mainly driven by three trends:
- Rising crude oil prices support increased production from tight oil formations with significant volumes of associated natural gas.
- Many oil wells are aging, and as these wells age, they tend to produce a higher ratio of natural gas relative to crude oil.
- Associated natural gas is becoming more economical to process, driven in part by provisions in the IRA that created penalties for venting and flaring methane, spurring producers to capture more natural gas from oil formations.
We project that associated natural gas production in the United States will increase from 19.8 Bcf/d in 2025 to 24.2 Bcf/d in 2050 in the AEO2023 Reference case. In the AEO2023 High Oil Price case, associated natural gas production peaks at 37.3 Bcf/d in 2035, accounting for 30% of the total domestic natural gas production. By contrast, in the AEO2023 Low Oil Price case, associated natural gas production falls to 11.4 Bcf/d by 2050.
Market Highlights:
(For the week ending Wednesday, May 17, 2023)Prices
- Henry Hub spot price: The Henry Hub spot price rose 13 cents from $2.12 per million British thermal units (MMBtu) last Wednesday to $2.25/MMBtu yesterday.
- Henry Hub futures prices: The price of the June 2023 NYMEX contract increased 17.4 cents, from $2.191/MMBtu last Wednesday to $2.365/MMBtu yesterday. The price of the 12-month strip averaging June 2023 through May 2024 futures contracts climbed 14.3 cents to $3.060/MMBtu.
- Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, May 10, to Wednesday, May 17), with few exceptions. Price changes at major pricing hubs this report week ranged from an increase of $1.12/MMBtu at the Waha hub in West Texas to a decrease of 3 cents/MMBtu at PG&E Citygate in Northern California.
- In the Northeast, prices rose this week but remained below $2.00/MMBtu. At the Algonquin Citygate, which serves Boston-area consumers, the price increased 31 cents from $1.36/MMBtu last Wednesday to $1.67/MMBtu yesterday. The price at the Eastern Gas South trading point in southwest Pennsylvania rose 24 cents from $1.15/MMBtu last Wednesday to $1.39/MMBtu yesterday. Total consumption of natural gas decreased week over week across the region by 8%, or 1.2 billion cubic feet per day (Bcf/d), to a weekly average of 14.4 Bcf/d, led by a 26% (1.3 Bcf/d) decrease in consumption in the residential and commercial sectors. Almost 60% of the decline in total consumption across the Northeast was in Appalachia, where consumption fell 9% (0.7 Bcf/d). In the Pittsburgh Area, temperatures averaged 62°F this week, which is 5°F higher than last week, leading to 34 fewer heating degree days (HDDs) than last week.
- In the Midwest, at the Chicago Citygate, the price increased 38 cents from $1.79/MMBtu last Wednesday to $2.17/MMBtu yesterday, which is 8 cents lower than the Henry Hub price. Total consumption in the Midwest increased 4% (0.4 Bcf/d) compared with last week, led by a 21% (0.5 Bcf/d) increase in consumption in the electric power sector. Across the Midwest, the number of cooling degree days (CDDs) increased from 2 CDDs to 9 CDDs week over week, as temperatures fluctuated around 65°F during the week, increasing the demand for air conditioning.
- Across most of the West, prices rose this week to above $2/MMBtu. In California, the price at SoCal Citygate in Southern California increased 78 cents from $1.80/MMBtu last Wednesday to $2.58/MMBtu yesterday. Consumption of natural gas in the residential and commercial sectors decreased by 27% (0.5 Bcf/d), while consumption in the electric power sector increased by 57% (0.4 Bcf/d). Temperatures across the state increased, leading to lower demand for heating and a switch to demand for air conditioning. In the Riverside Area, east of Los Angeles, temperatures averaged 69°F this report week, which is 9°F higher than last week, leading to 2 HDDs and 30 CDDs, compared with last week when there were 30 HDDs and no CDDs.
- In Northern California, prices continue to be relatively elevated. The price at PG&E Citygate in Northern California fell 3 cents, down from $4.16/MMBtu last Wednesday to $4.13/MMBtu yesterday. Prices at PG&E Citygate remain the highest among major hubs. Two ongoing maintenance events on PG&E pipelines continue to affect natural gas flows in California, as reported last week.
- 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 fell 65 cents to a weekly average of $10.62/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands fell $1.17 to a weekly average of $10.44/MMBtu. In the same week last year (week ending May 18, 2022), the prices were $21.65/MMBtu in East Asia and $29.72/MMBtu at TTF.
- Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 21 cents/MMBtu, averaging $6.03/MMBtu for the week ending May 17. Weekly average ethane prices rose 2%, while natural gas prices at the Houston Ship Channel fell 2%, widening the ethane premium to natural gas by 10% week over week. Ethylene spot prices fell by 2%, decreasing the ethylene to ethane premium by 4%. Propane prices fell 7%, and the Brent crude oil price fell 1%, resulting in an 8% increase in the propane discount relative to crude oil. The normal butane and isobutane prices each fell 5%, and the natural gasoline price fell 2%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas fell by 0.4% (0.4 Bcf/d) compared with the previous report week. Dry natural gas production increased slightly (less than 0.1 Bcf/d), while average net imports from Canada decreased by 9.6% (0.5 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas fell by 1.0% (0.6 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation climbed by 7.8% (2.4 Bcf/d) week over week as demand for air conditioning has started to rise in some parts of the country. In the residential and commercial sectors, consumption declined by 20.1% (2.7 Bcf/d), and industrial sector consumption decreased by 1.6% (0.3 Bcf/d) week over week. Natural gas exports to Mexico decreased 4.1% (0.2 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.8 Bcf/d, or 0.1 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Natural gas deliveries to U.S. LNG export terminals decreased by 0.8%, or 0.1 Bcf/d week over week, to average 12.8 Bcf/d this report week, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana decreased by 1% (0.1 Bcf/d) to 7.4 Bcf/d, while natural gas deliveries to all other terminals were essentially unchanged. Feedgas deliveries to U.S. LNG export terminals yesterday were 13% (2.0 Bcf/d) lower than the all-time daily high of 14.9 Bcf/d set in mid-April. Demand for feedgas at U.S. export terminals typically declines at this time of year, when exports are seasonally lower.
- Vessels departing U.S. ports: Twenty-four LNG vessels (eight from Sabine Pass; four from Freeport; three each from Calcasieu Pass, Cameron, and Corpus Christi; two from Cove Point; and one from Elba Island) with a combined LNG-carrying capacity of 90 Bcf departed the United States between May 11 and May 17, according to shipping data provided by Bloomberg Finance, L.P.
- LNG terminals: Sempra, operator of Cameron LNG in southwest Louisiana, reported that scheduled maintenance on Train 2 began on April 28. Natural gas deliveries to Cameron LNG averaged 1.2 Bcf/d this week, about 0.9 Bcf/d lower than the week before maintenance began, according to data from S&P Global Commodity Insights.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, May 9, the natural gas rig count decreased by 16 to 141 rigs, the largest week-over-week decline in the natural gas-directed rig count since February 2016. The Haynesville dropped five rigs, the Eagle Ford dropped four rigs, the Marcellus dropped three rigs, the Permian and Utica each dropped one rig, and two rigs were dropped in unspecified producing regions. The number of oil-directed rigs fell by 2 to 586 rigs. The Cana Woodford and Permian each dropped two rigs, the DJ-Niobrara and Williston each dropped one rig; the Eagle Ford added two rigs, and two rigs were added in unspecified producing regions. The total rig count decreased by 17, and it now stands at 731 rigs, which includes 4 miscellaneous rigs (an increase of 1 miscellaneous rig over last week).
Storage
- Net injections into storage totaled 99 Bcf for the week ending May 12, compared with the five-year (2018–2022) average net injections of 91 Bcf and last year's net injections of 87 Bcf during the same week. Working natural gas stocks totaled 2,240 Bcf, which is 340 Bcf (18%) more than the five-year average and 521 Bcf (30%) 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 100 Bcf to 116 Bcf, with a median estimate of 108 Bcf.
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Data source: U.S. Energy Information Administration, Annual Energy Outlook 2023 (AEO2023)
Data source: U.S. Energy Information Administration, Annual Energy Outlook 2023 (AEO2023)
| Spot Prices ($/MMBtu) | Thu, 11-May |
Fri, 12-May |
Mon, 15-May |
Tue, 16-May |
Wed, 17-May |
|---|---|---|---|---|---|
| Henry Hub |
2.06 |
1.98 |
2.25 |
2.30 |
2.25 |
| New York |
1.18 |
1.10 |
1.39 |
1.54 |
1.52 |
| Chicago |
1.80 |
1.87 |
2.20 |
2.33 |
2.17 |
| Cal. Comp. Avg.* |
2.45 |
2.37 |
2.86 |
3.06 |
2.92 |
| Futures ($/MMBtu) | |||||
| June contract | 2.190 |
2.266 |
2.375 |
2.376 |
2.365 |
| July contract |
2.345 |
2.438 |
2.542 |
2.534 |
2.509 |
| *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: (5/11/23 - 5/17/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 113.4 |
113.4 |
109.9 |
| Dry production | 100.8 |
100.8 |
97.2 |
| Net Canada imports | 4.4 |
4.8 |
4.8 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 105.2 |
105.6 |
102.1 |
|
Data source: S&P Global Commodity Insights | |||
| U.S. natural gas consumption - Gas Week: (5/11/23 - 5/17/23) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 64.7 |
65.3 |
62.7 |
| Power | 32.9 |
30.5 |
30.8 |
| Industrial | 21.2 |
21.6 |
21.4 |
| Residential/commercial | 10.6 |
13.2 |
10.6 |
| Mexico exports | 5.6 |
5.8 |
6.0 |
| Pipeline fuel use/losses | 6.7 |
6.7 |
6.4 |
| LNG pipeline receipts | 12.8 |
12.9 |
12.0 |
| Total demand | 89.7 |
90.7 |
87.2 |
|
Data source: S&P Global Commodity Insights | |||
| Rigs | |||
|---|---|---|---|
Tue, May 09, 2023 |
Change from |
||
last week |
last year |
||
| Oil rigs | 586 |
-0.3% |
4.1% |
| Natural gas rigs | 141 |
-10.2% |
-5.4% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, May 09, 2023 |
Change from |
||
last week |
last year |
||
| Vertical | 19 |
-9.5% |
-24.0% |
| Horizontal | 660 |
-2.4% |
1.4% |
| Directional | 52 |
2.0% |
36.8% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2023-05-12 |
2023-05-05 |
change |
|
| East | 458 |
422 |
36 |
|
| Midwest | 520 |
497 |
23 |
|
| Mountain | 112 |
104 |
8 |
|
| Pacific | 127 |
114 |
13 |
|
| South Central | 1,023 |
1,002 |
21 |
|
| Total | 2,240 |
2,141 |
99 |
|
| 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 (5/12/22) |
5-year average (2018-2022) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 293 |
56.3 |
345 |
32.8 |
|
| Midwest | 361 |
44.0 |
402 |
29.4 |
|
| Mountain | 102 |
9.8 |
108 |
3.7 |
|
| Pacific | 186 |
-31.7 |
212 |
-40.1 |
|
| South Central | 776 |
31.8 |
833 |
22.8 |
|
| Total | 1,719 |
30.3 |
1,900 |
17.9 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending May 11) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 58 |
-20 |
-28 |
0 |
0 |
0 |
||
| Middle Atlantic | 48 |
-16 |
-18 |
0 |
-1 |
0 |
||
| E N Central | 39 |
-30 |
-14 |
3 |
-3 |
-12 |
||
| W N Central | 25 |
-35 |
-11 |
23 |
15 |
-3 |
||
| South Atlantic | 21 |
-5 |
-16 |
37 |
7 |
0 |
||
| E S Central | 11 |
-13 |
-4 |
38 |
17 |
4 |
||
| W S Central | 1 |
-6 |
-2 |
71 |
26 |
-22 |
||
| Mountain | 73 |
0 |
14 |
6 |
-9 |
-13 |
||
| Pacific | 74 |
30 |
9 |
0 |
-6 |
0 |
||
| United States | 41 |
-10 |
-7 |
20 |
5 |
-5 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending May 11, 2023
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending May 11, 2023
Data source: National Oceanic and Atmospheric Administration
