In the News:
Growth in Argentina’s shale gas production leads to LNG exports
On June 6, 2019, Argentina shipped its first export cargo of liquefied natural gas (LNG), which was produced on a floating LNG production barge. The barge, Tango FLNG, is located at the Bahia Blanca port, has an LNG production capacity of 500,000 metric tons (0.07 billion cubic feet per day (Bcf/d)) and is expected to produce up to eight LNG export cargoes per year. The vessel carrying LNG cargo—Fuji LNG—loaded 30,000 cubic meters (0.7 billion cubic feet) of LNG, or 20% of its capacity, according to SP Global Platts. Fuji LNG may load additional LNG at another export facility before traveling to its final destination.
Natural gas demand seasonality and growth in shale production have supported the development of LNG exports in Argentina. Argentina’s natural gas consumption peaks during the austral winter (May to September) and remains relatively low during the rest of the year. Argentina’s off-peak season coincides with the winter peak demand season in major LNG consuming countries. Domestic natural gas production exceeds consumption during off-peak season, but is insufficient to meet demand during the winter peak season, which requires Argentina to import natural gas by both pipeline and as LNG. Argentina currently does not have large-scale natural gas storage facilities, and natural gas producers have had to shut-in surplus production to accommodate the shifting seasonal consumption patterns. Argentina is currently conducting feasibility studies to identify potential natural gas storage sites.
Tango FLNG is supplied by natural gas produced in the Vaca Muerta shale formation. The natural gas is transported via an existing pipeline network to the port of Bahía Blanca and then liquefied aboard the vessel. These pipelines were previously used to transport imported LNG from the Floating Storage and Regasification vessel (FSRU) moored at Bahía Blanca port.
During the last three years, Argentina has seen growing shale gas production, which has more than tripled between January and December 2018, from 0.3 Bcf/d to 1.0 Bcf/d. This growth has partially offset steady declines in natural gas production from mature fields, which decreased by more than one-third between 2009 and 2018. In addition to producing natural gas from shale formations, Argentina also produces tight gas. Production of tight gas started earlier than shale gas production and reversed the declining natural gas production trend in Argentina in 2014–2017. However, tight gas production has remained at the same level (around 1 Bcf/d) since 2016.
Recent growth in shale gas production was stimulated in large part by the economic incentives the Argentinian government offered for producing natural gas from tight and shale formations. Those incentives guaranteed producers minimum prices of $7.50 per million British thermal units (MMBtu) in 2018, decreasing by $0.50/MMBtu annually until 2021. In 2017, the Argentinian government also suspended import tariffs on used imported equipment, such as drilling rigs, further reducing shale production costs. Although government subsidy programs supporting shale and tight gas production were suspended in January 2019, shale production has remained stable as of April 2019.
Overview:
(For the week ending Wednesday, June 19, 2019)
- Natural gas spot price movements were mixed this report week (Wednesday, June 12 to Wednesday, June 19). Henry Hub spot prices remained flat at $2.36 per million British thermal units (MMBtu).
- At the New York Mercantile Exchange (Nymex), the price of the July 2019 contract decreased 11¢, from $2.386/MMBtu last Wednesday to $2.276/MMBtu yesterday. The price of the 12-month strip averaging July 2019 through June 2020 futures contracts declined 9¢/MMBtu to $2.442/MMBtu.
- Net injections to working gas totaled 115 billion cubic feet (Bcf) for the week ending June 14. Working natural gas stocks are 2,203 Bcf, which is 10% more than the year-ago level and 8% lower than the five-year (2014–18) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 12¢/MMBtu, averaging $4.20/MMBtu for the week ending June 19. The price of ethane, propane, and butane fell by 6%, 5%, and 1%, respectively. The price of natural gasoline and isobutane rose by 1% and 2%, respectively.
- According to Baker Hughes, for the week ending Tuesday, June 11, the natural gas rig count decreased by 5 to 181. The number of oil-directed rigs fell by 1 to 788. The total rig count decreased by 6, and it now stands at 969.
Prices/Supply/Demand:
Prices remained relatively flat at major trading hubs. From Wednesday, June 12 to Wednesday, June 19, Henry Hub spot prices remained flat at $2.36/MMBtu, trading within a 9¢/MMBtu range throughout the report week. Prices also remained unchanged week over week at the Chicago Citygate, closing at $2.18/MMBtu yesterday; however, prices reached a weekly low of $1.98/MMBtu last Friday. And at the Opal hub in southwestern Wyoming, prices fell 6¢ from $2.01/MMBtu last Wednesday to $1.96/MMBtu yesterday.
Temperatures began the report week cooler-than-normal across the eastern and central United States and much warmer-than-normal in the West. This pattern persisted through the report week as temperatures moderated in the western United States―particularly in the Southwest― resulting in stable or declining demand for space heating and cooling.
California prices fall with cooler-than-normal temperatures. Prices at PG&E Citygate in Northern California fell 18¢, down from $2.88/MMBtu last Wednesday to $2.70/MMBtu yesterday. Prices at SoCal Citygate in Southern California also decreased, falling 63¢ from $3.03/MMBtu last Wednesday to $2.40/MMBtu yesterday. Although the report week began with warmer-than-normal temperatures in both Northern and Southern California, weather moderated through the weekend and is forecast to remain cooler-than-normal for the next several days.
Northeastern prices increase in demand markets. At the Algonquin Citygate, which serves Boston-area consumers, prices went up 2¢ from $2.15/MMBtu last Wednesday to $2.17/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 8¢ from $2.11/MMBtu last Wednesday to $2.19/MMBtu yesterday.
Tennessee Zone 4 Marcellus spot prices decreased 2¢ from $2.00/MMBtu last Wednesday to $1.98/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 2¢ from $2.02/MMBtu last Wednesday to $2.04/MMBtu yesterday.
Permian Basin prices fall but end the report week in positive territory. Prices at the Waha Hub in West Texas, which is located near the Permian Basin production activities, closed at $0.45/MMBtu last Wednesday, $1.91/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub closed at $0.19/MMBtu, $2.17/MMBtu lower than Henry Hub prices. This week the Waha index saw several days of negative prices in the middle of the week, but they traded positive toward the end of the week. The region continues to experience mild weather and ongoing capacity constraints, both of which put downward pressure on prices.
Supply is flat despite declining Canadian imports. According to data from PointLogic Energy, the average total supply of natural gas remained the same as in the previous report week, averaging 93.8 Bcf/d. Although dry natural gas production remained constant week over week, average net imports from Canada decreased by 9% from last week as the Alliance Pipeline issued a force majeure on Tuesday, June 18, halting deliveries into the United States. The pipeline, which is expected to resume operations on June 22, was flowing at capacity (1.77 Bcf/d) before the outage.
Demand falls slightly, driven by declining natural consumption in the electric power sector. Total U.S. consumption of natural gas fell by 1% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation declined by 1% week over week. Industrial sector consumption decreased by 2% week over week. In the residential and commercial sectors, consumption increased by 3%. Natural gas exports to Mexico increased 2%.
U.S. LNG exports increase week over week. Eleven LNG vessels (eight from Sabine Pass, two from Corpus Christi, and one from Cove Point) with a combined LNG-carrying capacity of 39.1 Bcf departed the United States between June 13 and June 19, according to shipping data compiled by Bloomberg. One vessel was loading at the Sabine Pass terminal on Wednesday.
Cheniere Energy, the developer of the Sabine Pass and Corpus Christi LNG export terminals in Louisiana and Texas, respectively, reported on June 13 that the second train at Corpus Christi facility has started LNG production. Corpus Christi will be a three-train facility, with Train 1 in operation since December 2018, and two other trains under construction. The first cargo from Corpus Christi Train 2 is expected to load in the next four weeks.
Storage:
Net injections into storage totaled 115 Bcf for the week ending June 14, compared with the five-year (2014–18) average net injections of 84 Bcf and last year's net injections of 95 Bcf during the same week. Working gas stocks totaled 2,203 Bcf, which is 199 Bcf lower than the five-year average and 209 Bcf more than last year at this time.
According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas stocks ranged from net injections of 97 Bcf to 112 Bcf, with a median estimate of 104 Bcf.
The average rate of net injections into storage is 39% 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 9.3 Bcf/d for the remainder of the refill season, total inventories would be 3,493 Bcf on October 31, which is 199 Bcf lower than the five-year average of 3,692 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:
Source: U.S. Energy Information Administration based on Secretaría de Gobierno de Energía de Argentina
| Spot Prices ($/MMBtu) | Thu, 13-Jun |
Fri, 14-Jun |
Mon, 17-Jun |
Tue, 18-Jun |
Wed, 19-Jun |
|---|---|---|---|---|---|
| Henry Hub |
2.30 |
2.31 |
2.39 |
2.38 |
2.36 |
| New York |
2.00 |
2.11 |
2.23 |
2.18 |
2.19 |
| Chicago |
2.10 |
1.98 |
2.22 |
2.20 |
2.18 |
| Cal. Comp. Avg.* |
2.31 |
2.01 |
2.42 |
2.30 |
2.28 |
| Futures ($/MMBtu) | |||||
| July contract | 2.325 |
2.387 |
2.386 |
2.328 |
2.276 |
| August contract |
2.322 |
2.381 |
2.373 |
2.311 |
2.263 |
| *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. | |||||
| Sources: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. | |||||
| U.S. natural gas supply - Gas Week: (6/13/19 - 6/19/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 99.8 |
99.4 |
90.8 |
| Dry production | 89.0 |
88.6 |
80.7 |
| Net Canada imports | 4.7 |
5.1 |
6.1 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 93.8 |
93.8 |
86.9 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (6/13/19 - 6/19/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 65.1 |
65.6 |
61.5 |
| Power | 34.1 |
34.4 |
32.1 |
| Industrial | 20.9 |
21.4 |
21.2 |
| Residential/commercial | 10.2 |
9.8 |
8.2 |
| Mexico exports | 5.2 |
5.1 |
4.7 |
| Pipeline fuel use/losses | 6.1 |
6.1 |
5.6 |
| LNG pipeline receipts | 5.5 |
5.3 |
3.3 |
| Total demand | 81.9 |
82.0 |
75.0 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Tue, June 11, 2019 |
Change from |
||
last week |
last year |
||
| Oil rigs | 788 |
-0.1% |
-8.7% |
| Natural gas rigs | 181 |
-2.7% |
-6.7% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, June 11, 2019 |
Change from |
||
last week |
last year |
||
| Vertical | 0 |
0.0% |
-100.0% |
| Horizontal | 15 |
-25.0% |
-37.5% |
| Directional | 68 |
-8.1% |
1.5% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2019-06-14 |
2019-06-07 |
change |
|
| East | 472 |
440 |
32 |
|
| Midwest | 503 |
469 |
34 |
|
| Mountain | 118 |
111 |
7 |
|
| Pacific | 234 |
227 |
7 |
|
| South Central | 875 |
842 |
33 |
|
| Total | 2,203 |
2,088 |
115 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (6/14/18) |
5-year average (2014-2018) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 402 |
17.4 |
484 |
-2.5 |
|
| Midwest | 397 |
26.7 |
530 |
-5.1 |
|
| Mountain | 127 |
-7.1 |
151 |
-21.9 |
|
| Pacific | 245 |
-4.5 |
277 |
-15.5 |
|
| South Central | 824 |
6.2 |
960 |
-8.9 |
|
| Total | 1,994 |
10.5 |
2,402 |
-8.3 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jun 13) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 20 |
2 |
1 |
5 |
-4 |
2 |
||
| Middle Atlantic | 11 |
-2 |
2 |
10 |
-11 |
0 |
||
| E N Central | 15 |
-1 |
11 |
16 |
-13 |
-19 |
||
| W N Central | 19 |
5 |
17 |
28 |
-10 |
-39 |
||
| South Atlantic | 1 |
-2 |
0 |
72 |
4 |
-2 |
||
| E S Central | 4 |
2 |
4 |
59 |
-3 |
-26 |
||
| W S Central | 1 |
1 |
1 |
86 |
-8 |
-41 |
||
| Mountain | 25 |
-1 |
19 |
51 |
4 |
-16 |
||
| Pacific | 5 |
-14 |
-3 |
42 |
23 |
22 |
||
| United States | 11 |
-2 |
6 |
43 |
-1 |
-10 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Jun 13, 2019
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Jun 13, 2019
Source: National Oceanic and Atmospheric Administration
