In the News:
U.S. ammonia production is growing, and becoming less carbon intensive
Globally, ammonia production is a carbon-intensive process, and 98% of ammonia plants around the world use fossil fuels as a feedstock, primarily natural gas (72%) and coal (22%). U.S. ammonia production, the third-largest in the world behind China and Russia, is dominated by less carbon intensive natural gas-fed ammonia plants, which account for 92% of all U.S. ammonia production. Recent expansions to U.S. ammonia capacity, which have been spurred by growing natural gas production and the resulting low natural gas prices, have allowed the industry to expand domestic ammonia production while continuing the trend of reducing carbon intensity.
Growth in ammonia production and its declining carbon intensity are consistent with broader global goals of transitioning away from carbon-based fuels. In a push to decarbonize their economies, countries around the world are looking to hydrogen as an energy carrier to replace natural gas where requirements for heat or feedstock cannot be met with biofuels or electricity. Hydrogen, however, presents challenges because it requires extremely high pressure (5,000 pounds per square inch or higher) or cryogenic temperatures (below -423ºF) to store and pipelines made of specialized steel to transport. Recent advances in engine and turbine technology may lead to using ammonia as a hydrogen carrier, consuming the ammonia either directly for combustion or reforming it back into nitrogen and hydrogen and using the hydrogen as industrial feedstock.
Unlike hydrogen, ammonia has the advantages of an existing broad user base and a well-developed infrastructure. In the United States, ammonia is used primarily as a fertilizer or as a feedstock in producing fertilizers (for example, urea), but its use in the chemical industry is growing. Ammonia is produced at 32 plants in 17 states and shipped around the country by pipeline, rail, barge, and truck. According to the U.S. Geological Survey, U.S. ammonia production has been increasing since 2015, rising 46% from 11.6 million metric tons per year (mt/y) to 17.0 million mt/y in 2020. With growth in domestic production outpacing growth in demand, U.S. reliance on imported ammonia has decreased from 40% in 2010 to 13% in 2020.
For ammonia to serve as a hydrogen carrier in a decarbonized economy, ammonia production would need to become carbon neutral. The Haber-Bosch process, which uses hydrogen obtained from steam methane reforming and nitrogen from the air, remains the dominant method of producing ammonia. Ammonia produced from natural gas is the primary source of U.S. ammonia production, and at approximately 1.5 billion cubic feet per day (Bcf/d) ammonia production accounted for 6.5% of all U.S. industrial natural gas consumption in 2020. Although cleaner relative to the global average, the U.S. emission rate is about 2.1 tons of carbon dioxide per every ton of ammonia produced, which includes emissions from both the combustion of natural gas for process heat and from its use as a feedstock in the steam methane reformer.
To avoid carbon emissions altogether, a plant must either sequester the carbon dioxide, resulting in blue ammonia, or use hydrogen produced by electrolysis of water using renewable-generated electricity, which is referred to as green ammonia. Currently, the United States has only one blue ammonia plant, the coal-fed Dakota Gasification Co. in Beulah, North Dakota, which captures and sequesters its emissions of carbon dioxide by piping it to nearby oil fields for enhanced oil recovery.
The newest U.S. ammonia plant, the Yara/BASF plant in Freeport, Texas, which was completed in April 2018, does not use a steam methane reformer to supply hydrogen for its Haber-Bosch process. Instead, it uses surplus hydrogen from neighboring petrochemical facilities, such as propane dehydrogenation (PDH) plants or ethylene crackers, which would normally combust the hydrogen for process heat.
CF Industries, the largest ammonia producer in the country, is planning to construct the first green ammonia plant in the United States in Donaldsonville, Louisiana. By 2023, the new plant will produce 20,000 mt/y of ammonia using hydrogen produced by electrolysis of water using renewable-generated electricity.
Overview:
(For the week ending Wednesday, March 24, 2021)
- Natural gas spot prices rose at most locations this report week (Wednesday, March 24 to Wednesday, March 31). The Henry Hub spot price rose from $2.45 per million British thermal units (MMBtu) last Wednesday to $2.49/MMBtu yesterday.
- At the New York Mercantile Exchange (NYMEX), the April 2021 contract expired Monday at $2.586/MMBtu, up 7¢/MMBtu from last Wednesday. The May 2021 contract price increased to $2.608/MMBtu, up 4¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging May 2021 through April 2022 futures contracts climbed 4¢/MMBtu to $2.782/MMBtu.
- The net injections to working gas totaled 14 billion cubic feet (Bcf) for the week ending March 26. Working natural gas stocks totaled 1,764 Bcf, which is 11% lower than the year-ago level and 2% lower than the five-year (2016–2021) average for this week.
- The natural gas plant liquids (NGPL) composite price at Mont Belvieu, Texas, rose by 5¢/MMBtu, averaging $7.51/MMBtu for the week ending March 31. Similar to average weekly crude oil prices, which remained flat week over week, NGPL prices moved within a narrow band. The prices of natural gasoline, ethane, propane, and butane all rose by 1%. The price of isobutane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, March 23, the natural gas rig count remained flat at 92. The number of oil-directed rigs rose by 6 to 324. The number of oil-directed rigs for the last week of March was 144 higher than for the last week of July 2020. This increase is consistent with rising crude oil prices, which rose from an average of $42.83/barrel in July 2020 to an average of $66.65/barrel in March 2021. The Permian Basin has seen the strongest growth in rig count and rose by 5 in the last week of March. The total rig count increased by 6, and it now stands at 417.
Prices/Supply/Demand:
Prices in most markets increase slightly week over week, reflecting mixed weather across the country. The Henry Hub spot price moved only slightly throughout the report week (Wednesday, March 24 to Wednesday, March 31), rising 4¢ per million British thermal units (MMBtu) from $2.45/MMBtu last Wednesday to $2.49/MMBtu yesterday after reaching a high of $2.51/MMBtu on Monday.
Prices in the Northwest rose. Sustained below-normal temperatures across the region resulted in elevated demand and higher prices. At the Sumas border crossing, the main delivery point for natural gas into the Northwest, the price increased 26¢/MMBtu from $2.30/MMBtu last Wednesday to $2.56/MMBtu yesterday. Temperatures in Seattle remained in the mid-40’s, which was, on average, 5ºF below normal.
Cooling trend across the Great Lakes resulted in higher Midwest prices at the end of the report week. After staying well above normal for most of the report week, temperatures in the Midwest fell sharply yesterday. Yesterday’s reported temperature in Chicago fell to 39ºF, 4ºF below normal, from an average of 59ºF (16ºF above normal) on Tuesday. Natural Gas Intelligence’s Midwest regional average price stayed relatively flat through most of the week, moving within a 6¢/MMBtu range relative to last Wednesday's price of $2.32/MMBtu. The Midwest regional price fell to a low of $2.30/MMBtu last Friday and rose to $2.38/MMBtu on Tuesday before rising sharply to $2.51/MMBtu yesterday. At the Chicago Citygate, the price increased 21¢ from $2.34/MMBtu last Wednesday to $2.55/MMBtu yesterday with a low of $2.30/MMBtu on Friday.
California prices rise slightly as pipeline maintenance-induced constraints remain. Temperatures across California rose to above normal for the week, easing heating demand relative to the previous week, when below-normal temperatures were recorded in both major California markets. Continuing maintenance at the Bethany Compressor Station near the Bay Area, on PG&E system’s Line 400, reduced flows on the pipeline to 69% of normal capacity and limited withdrawals from storage facilities along the pipeline path. The price at PG&E Citygate in Northern California rose 2¢, up from $3.62/MMBtu last Wednesday to $3.64/MMBtu yesterday, after reaching a weekly low of $3.59 on Friday. The price at SoCal Citygate in Southern California increased 3¢ from $2.97/MMBtu last Wednesday to $3.00/MMBtu yesterday after falling to $2.61/MMBtu on Monday.
Forecast cooler temperatures through the end of the week push up prices across the Northeast. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 61¢ from $1.93/MMBtu last Wednesday to $2.54/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 64¢ from $1.79/MMBtu last Wednesday to $2.43/MMBtu yesterday. Both pricing points reported lowest prices for the report week on Friday at $1.80/MMBtu and $1.61/MMBtu, respectively.
Prices in the Appalachia Basin-producing region also rise, moved higher by an anticipated rise in demand in the Northeast. The Tennessee Zone 4 Marcellus spot price increased 31¢ from $1.68/MMBtu last Wednesday to $1.99/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania rose 37¢ from $1.75/MMBtu last Wednesday to $2.12/MMBtu yesterday. Reflecting the same trend as prices in the Northeast demand region, prices at both hubs fell to weekly lows on Friday to $1.40/MMBtu at Tennessee Zone 4 and $1.70/MMBtu at Dominion South.
Prices in the Permian production region decrease slightly, bucking the national trend of rising prices this report week. IHS Markit reports average weekly production in West Texas continuing to rise, surpassing an estimated 8.5 billion cubic feet per day (Bcf/d) for the first time since the second week of February. Increasing crude oil prices are supporting Permian drilling activity, as the number of oil-directed rigs in the Permian Basin rises. The growth in crude oil directed activity in turn supports growth in natural gas production, resulting in the price at the Waha Hub in West Texas falling 3¢/MMBtu this report week, from $2.31/MMBtu last Wednesday to $2.28/MMBtu yesterday. The discount between the Waha Hub and the Henry Hub natural gas prices expanded from 14¢/ last Wednesday to 21¢/MMBtu yesterday.
U.S. production rises slightly week-over-week. According to data from IHS Markit, the average total supply of natural gas fell by 0.1% compared with the previous report week. Dry natural gas production grew by 0.2% compared with the previous report week, reaching an average of 91.3 Bcf/d, about 2.0 Bcf/d lower than this time last year. Average net imports from Canada decreased by 6.7% from last week.
U.S. demand declines again week over week due to mild temperatures. Total U.S. consumption of natural gas fell by 6.0% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed 1.4% week over week. Industrial sector consumption decreased 1.9% week over week. The largest decrease in consumption came from the residential and commercial sectors, where consumption declined by 17.1% due to above-average temperatures and low heating demand in the eastern United States for much of last report week. Natural gas exports to Mexico increased 2.6%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) were flat from last week’s level of 11.6 Bcf/d.
U.S. LNG exports increase week over week. Twenty-four liquefied natural gas (LNG) vessels (eight from Sabine Pass, six from Freeport, five from Corpus Christi, three from Cameron, and two from Cove Point) with a combined LNG-carrying capacity of 87 Bcf departed the United States between March 25 and March 31, 2021, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 14 Bcf for the week ending March 26, compared with the five-year (2016–2021) average net withdrawals of 24 Bcf and last year's net withdrawals of 20 Bcf during the same week. Working natural gas stocks totaled 1,764 Bcf, which is 36 Bcf lower than the five-year average and 225 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 11 Bcf to 41 Bcf, with a median estimate of 21 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, 25-Mar |
Fri, 26-Mar |
Mon, 29-Mar |
Tue, 30-Mar |
Wed, 31-Mar |
|---|---|---|---|---|---|
| Henry Hub | 2.47 | 2.47 | 2.51 | 2.46 | 2.49 |
| New York | 1.75 | 1.61 | 1.94 | 1.88 | 2.43 |
| Chicago | 2.39 | 2.30 | 2.33 | 2.41 | 2.55 |
| Cal. Comp. Avg,* | 2.86 | 2.73 | 2.76 | 2.81 | 2.83 |
| Futures ($/MMBtu) | |||||
| April Contract | 2.570 | 2.557 | 2.586 | Expired | Expired |
| May Contract | 2.616 | 2.619 | 2.653 | 2.623 | 2.608 |
| June Contract | 2.676 | 2.679 | 2.708 | 2.681 | 2.667 |
| *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: (3/25/21 - 3/31/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 103.3 |
103.1 |
106.2 |
| Dry production | 91.3 |
91.1 |
93.3 |
| Net Canada imports | 4.1 |
4.4 |
3.9 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 95.4 |
95.6 |
97.3 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (3/25/21 - 3/31/21) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 68.4 |
72.8 |
74.6 |
| Power | 24.8 |
24.4 |
28.0 |
| Industrial | 23.0 |
23.5 |
22.4 |
| Residential/commercial | 20.6 |
24.9 |
24.2 |
| Mexico exports | 6.1 |
6.0 |
5.4 |
| Pipeline fuel use/losses | 6.3 |
6.4 |
6.7 |
| LNG pipeline receipts | 11.6 |
11.6 |
9.5 |
| Total demand | 92.5 |
96.8 |
96.1 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, March 23, 2021 |
Change from |
||
last week |
last year |
||
| Oil rigs | 324 |
1.9% |
-48.1% |
| Natural gas rigs | 92 |
0.0% |
-9.8% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, March 23, 2021 |
Change from |
||
last week |
last year |
||
| Vertical | 22 |
-12.0% |
-21.4% |
| Horizontal | 380 |
2.2% |
-41.8% |
| Directional | 15 |
7.1% |
-68.1% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2021-03-26 |
2021-03-19 |
change |
|
| East | 307 |
307 |
0 |
|
| Midwest | 401 |
405 |
-4 |
|
| Mountain | 112 |
112 |
0 |
|
| Pacific | 194 |
193 |
1 |
|
| South Central | 749 |
734 R |
15 |
|
| Total | 1,764 |
1,750 R |
14 |
|
|
R=Revised Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (3/26/20) |
5-year average (2016-2020) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 384 |
-20.1 |
310 |
-1.0 |
|
| Midwest | 478 |
-16.1 |
407 |
-1.5 |
|
| Mountain | 92 |
21.7 |
106 |
5.7 |
|
| Pacific | 197 |
-1.5 |
189 |
2.6 |
|
| South Central | 838 |
-10.6 |
787 |
-4.8 |
|
| Total | 1,989 |
-11.3 |
1,800 |
-2.0 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Mar 25) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 146 |
-41 |
-27 |
0 |
0 |
0 |
||
| Middle Atlantic | 133 |
-39 |
-19 |
0 |
0 |
0 |
||
| E N Central | 118 |
-62 |
-63 |
0 |
0 |
0 |
||
| W N Central | 138 |
-39 |
-42 |
0 |
-1 |
0 |
||
| South Atlantic | 83 |
-15 |
21 |
10 |
-2 |
-17 |
||
| E S Central | 68 |
-24 |
13 |
2 |
-3 |
-9 |
||
| W S Central | 57 |
3 |
23 |
7 |
-6 |
-22 |
||
| Mountain | 164 |
16 |
2 |
1 |
-2 |
1 |
||
| Pacific | 108 |
22 |
-12 |
0 |
-1 |
0 |
||
| United States | 113 |
-23 |
-19 |
3 |
-2 |
-6 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Mar 25, 2021
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Mar 25, 2021
Source: National Oceanic and Atmospheric Administration
