In the News:
Natural gas infrastructure in the Netherlands is changing in response to declining natural gas production
Dutch natural gas utilities and major industrial consumers are adapting existing infrastructure or building new facilities to prepare for continued declines in domestic natural gas production and increases in imported natural gas. Production from the Groningen field—the largest natural gas field in the Netherlands and one of the world’s 10 largest at total estimated recoverable resource of 102 trillion cubic feet (Tcf)—is declining. Since 1965, when commercial production from the Groningen field began, through June 2020, more than 79 Tcf of natural gas was produced.
In the past eight years, as a result of increasing seismic activity associated with the high depletion rate and 87 earthquakes registered in 2019, the Dutch government imposed increasingly stringent limits on annual production from the Groningen field. In January 2020, after several revisions, the production plan for 2020 was set at less than 1.0 Bcf/d under normal weather conditions, but actual production could be lower because of the impacts of actions taken to contain the spread of the COVID-19 pandemic. For 2021, the plan calls for a further reduction in production to approximately 0.5 Bcf/d. Starting in mid-2022, production from the Groningen field will be limited to when the weather is exceptionally cold, and be completely halted by 2030.
The Groningen field, as well as a number of smaller onshore fields in the Netherlands, produces lean gas (L-gas)—natural gas that has a relatively low heat content because of the presence of inert gasses (non-hydrocarbon gases that do not combust). Natural gas produced by the Groningen field contains more than 14% nitrogen, an inert non-hydrocarbon gas, which results in a heat content of 941 British thermal units per cubic foot (Btu/cf). By comparison, EIA reports heat content of natural gas delivered to U.S. consumers and to U.S. LNG terminals exporting natural gas overseas—including to the Netherlands—averaged 1,037 Btu/cf in 2019.
Because Dutch infrastructure was built to transport L-gas with heat content approximately 10% lower than in the imported higher-heat natural gas (H-gas), the country needs greater capacity of plants that blend nitrogen into imported gas to lower its heat content. On September 3, the Dutch Ministry for the Economy and Climate, along with Gasunie, the national natural gas utility, announced that it started construction of a new blending facility to process imported natural gas to make it suitable for delivery to consumers who cannot switch to H-gas. The Zuidbroek nitrogen blending plant will expand the capacity of the Dutch grid to blend natural gas by 0.7 billion cubic feet per day (Bcf/d) from 2.5 Bcf/d reported at the end of 2019.
The transformation of the Netherlands from a major natural gas exporter to a net importer has been relatively rapid. According to Statistics Netherlands (CBS), as recently as 2017, the Netherlands was a net exporter of natural gas to its European neighbors. From 2010 to 2014, natural gas exports (net negative imports) averaged about 3.0 Bcf/d. Domestic natural gas production in those years averaged 7.3 Bcf/d, with Groningen production contributing about 4.7 Bcf/d to the total. In 2018, the Netherlands became a net importer of natural gas for the first time, and net pipeline and LNG imports accounted for 14% of domestic consumption. Preliminary 2019 data indicate that natural gas imports contributed 25% to natural gas supply in the Netherlands. The role of natural gas imports, as well as nitrogen blending, is expected to increase as Dutch domestic production continues to decline.
Overview:
(For the week ending Wednesday, September 16, 2020)
- Natural gas spot prices fell at most locations this report week (Wednesday, September 9, to Wednesday, September 16). The Henry Hub spot price fell from $2.19 per million British thermal units (MMBtu) last Wednesday to $2.06/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the October 2020 contract decreased 14¢, from $2.406/MMBtu last Wednesday to $2.267/MMBtu yesterday. The price of the 12-month strip averaging October 2020 through September 2021 futures contracts declined 8¢/MMBtu to $2.880/MMBtu.
- The net injections to working gas totaled 89 billion cubic feet (Bcf) for the week ending September 11. Working natural gas stocks totaled 3,614 Bcf, which is 17% more than the year-ago level and 13% more than the five-year (2015–19) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 7¢/MMBtu, averaging $4.77/MMBtu for the week ending September 16. The prices of natural gasoline and propane each fell by 2%. The prices of ethane and butane rose by 6% and 10%, respectively. The price of isobutane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, September 8, the natural gas rig count decreased by 1 to 71. The number of oil-directed rigs fell by 1 to 180. The total rig count decreased by 2, and it now stands at 254.
Prices/Supply/Demand:
Prices fall at most locations with cooler fall temperatures. This report week (Wednesday, September 9, to Wednesday, September 16), the Henry Hub spot price fell 13¢ from $2.19/MMBtu last Wednesday to $2.06/MMBtu yesterday after reaching a low of $1.94/MMBtu on Friday. Temperatures were cooler than normal across most of the Lower 48 states and warmer than normal in the Southeast and Pacific Northwest. At the Chicago Citygate, the price decreased 3¢ from a high of $1.95/MMBtu last Wednesday to $1.92/MMBtu yesterday.
Hurricane Sally makes landfall on the Gulf Coast. Hurricane Sally made landfall as a Category 2 storm yesterday morning near Gulf Shores, Alabama. The Bureau of Safety and Environmental Enforcement (BSSE) reports that 19% of manned production platforms in the Gulf of Mexico have been evacuated as of yesterday. BSSE estimates that approximately 0.8 Bcf/d or 30%, of the current natural gas production and 27% of crude oil production in the Gulf of Mexico has been shut in.
California prices are down as the region continues to battle wildfires. The price at SoCal Citygate in Southern California decreased 31¢ from a high of $3.12/MMBtu last Wednesday to $2.81/MMBtu yesterday. The price at PG&E Citygate in Northern California fell 12¢, down from a high of $3.55/MMBtu last Wednesday to $3.43/MMBtu yesterday. The National Interagency Fire Center reports that 106 large wildfires are currently burning across the western United States and that approximately 6.7 million acres of land have burned this year. Smoke from wildfires obscured the sun, and helped keep temperatures across the Lower 48 states a bit cooler, according to the National Weather Service.
Northeast prices decrease. Temperatures in the region were generally close to 70 degrees Fahrenheit, reducing demand for air conditioning. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.21 from a high of $2.46/MMBtu last Wednesday to a low of $1.25/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 70¢ from a high of $1.66/MMBtu last Wednesday to $0.96/MMBtu yesterday, the lowest price since October of last year.
The Tennessee Zone 4 Marcellus spot price decreased 35¢ from $1.16/MMBtu last Wednesday to $0.81/MMBtu yesterday. The price at Dominion South in southwest Pennsylvania fell 61¢ from $1.51/MMBtu last Wednesday to $0.90/MMBtu yesterday.
Permian Basin prices strengthen with end of pipeline maintenance. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged a low of $1.24/MMBtu last Wednesday, 95¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $1.52/MMBtu, 54¢/MMBtu lower than the Henry Hub price. An ongoing force majeure on the El Paso Natural Gas Pipeline was lifted yesterday, supporting the increase in prices.
Supply falls amid shut-ins in Gulf of Mexico. According to data from IHS Markit, the average total supply of natural gas fell by 1.2% compared with the previous report week. Dry natural gas production decreased by 1.5% compared with the previous report week. Average net imports from Canada increased by 7.2% from last week.
Demand falls, driven by declines in power generation. Temperatures averaged 65–70 degrees Fahrenheit across most of the Lower 48 states, reducing cooling demand and energy consumption. Total U.S. consumption of natural gas fell by 3.0% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 6.3% week over week. In the residential and commercial sectors, consumption increased by 2.7%. Industrial sector consumption increased by 0.4%. Natural gas exports to Mexico decreased 5.7%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 7.0 Bcf/d, or 2.4 Bcf/d higher than last week. LNG pipeline receipts reached a high of 7.5 Bcf/d on September 13, the highest level since early May.
U.S. LNG exports increase week over week. A total of 11 LNG vessels (6 from Sabine Pass, 2 each from Corpus Christi and Freeport, and 1 from Cove Point) with a combined LNG-carrying capacity of 41 Bcf departed the United States between September 10 and September 16, 2020, according to shipping data provided by Marine Traffic.
Storage:
The net injections into storage totaled 89 Bcf for the week ending September 11, compared with the five-year (2015–19) average net injections of 77 Bcf and last year's net injections of 82 Bcf during the same week. Working natural gas stocks totaled 3,614 Bcf, which is 421 Bcf more than the five-year average and 535 Bcf 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 68 Bcf to 86 Bcf, with a median estimate of 80 Bcf.
The average rate of injections into storage is 7% higher 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 10.6 Bcf/d for the remainder of the refill season, the total inventory would be 4,144 Bcf on October 31, which is 421 Bcf higher than the five-year average of 3,723 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, 10-Sep |
Fri, 11-Sep |
Mon, 14-Sep |
Tue, 15-Sep |
Wed, 16-Sep |
|---|---|---|---|---|---|
| Henry Hub |
2.13 |
1.94 |
2.19 |
2.21 |
2.06 |
| New York |
1.42 |
1.23 |
1.23 |
1.31 |
0.96 |
| Chicago |
1.92 |
1.79 |
1.95 |
1.92 |
1.92 |
| Cal. Comp. Avg.* |
2.39 |
2.25 |
2.62 |
2.65 |
2.74 |
| Futures ($/MMBtu) | |||||
| October contract | 2.323 |
2.269 |
2.310 |
2.362 |
2.267 |
| November contract |
2.798 |
2.744 |
2.740 |
2.741 |
2.664 |
| *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: (9/10/20 - 9/16/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 99.1 |
100.7 |
104.5 |
| Dry production | 87.7 |
89.1 |
92.9 |
| Net Canada imports | 3.9 |
3.6 |
4.7 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 91.7 |
92.8 |
97.7 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (9/10/20 - 9/16/20) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 61.8 |
63.7 |
67.2 |
| Power | 32.8 |
35.0 |
37.8 |
| Industrial | 20.8 |
20.7 |
21.0 |
| Residential/commercial | 8.3 |
8.1 |
8.5 |
| Mexico exports | 5.7 |
6.0 |
5.2 |
| Pipeline fuel use/losses | 6.5 |
6.6 |
7.0 |
| LNG pipeline receipts | 7.0 |
4.6 |
6.4 |
| Total demand | 81.1 |
81.1 |
85.8 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, September 08, 2020 |
Change from |
||
last week |
last year |
||
| Oil rigs | 180 |
-0.6% |
-75.4% |
| Natural gas rigs | 71 |
-1.4% |
-53.6% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, September 08, 2020 |
Change from |
||
last week |
last year |
||
| Vertical | 19 |
18.8% |
-64.2% |
| Horizontal | 214 |
-2.7% |
-72.4% |
| Directional | 21 |
5.0% |
-63.2% |
| Source: Baker Hughes Co. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2020-09-11 |
2020-09-04 |
change |
|
| East | 825 |
805 |
20 |
|
| Midwest | 983 |
953 |
30 |
|
| Mountain | 221 |
216 |
5 |
|
| Pacific | 310 |
308 |
2 |
|
| South Central | 1,276 |
1,243 |
33 |
|
| Total | 3,614 |
3,525 |
89 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (9/11/19) |
5-year average (2015-2019) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 756 |
9.1 |
779 |
5.9 |
|
| Midwest | 888 |
10.7 |
882 |
11.5 |
|
| Mountain | 187 |
18.2 |
197 |
12.2 |
|
| Pacific | 278 |
11.5 |
299 |
3.7 |
|
| South Central | 969 |
31.7 |
1,036 |
23.2 |
|
| Total | 3,079 |
17.4 |
3,193 |
13.2 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Sep 10) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 2 |
-14 |
-21 |
31 |
22 |
25 |
||
| Middle Atlantic | 2 |
-8 |
-6 |
40 |
19 |
23 |
||
| E N Central | 22 |
7 |
5 |
18 |
-3 |
-6 |
||
| W N Central | 48 |
27 |
35 |
26 |
-4 |
-22 |
||
| South Atlantic | 0 |
-1 |
0 |
84 |
13 |
-13 |
||
| E S Central | 0 |
-1 |
0 |
74 |
12 |
-16 |
||
| W S Central | 3 |
1 |
3 |
96 |
0 |
-34 |
||
| Mountain | 40 |
16 |
32 |
60 |
12 |
-6 |
||
| Pacific | 0 |
-8 |
-3 |
69 |
34 |
32 |
||
| United States | 13 |
2 |
5 |
57 |
12 |
-1 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Sep 10, 2020
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Sep 10, 2020
Source: National Oceanic and Atmospheric Administration
