Updated September 7, 2017 to conform to data from PointLogic.
In the News:
U.S. ethane production and exports reach new high
Marketed ethane increased from an average of 0.9 million barrels per day (b/d) during the first quarter of 2013 to a record 1.4 million b/d in the second quarter of 2017. Growth in natural gas production has largely driven the dramatic increase in ethane production over the past 10 years. However, increased natural gas processing and takeaway capacity has allowed more ethane to be marketed for domestic consumption and for export and has reduced the volume of ethane left in the natural gas stream instead of being separated out (i.e., “rejected”). EIA expects ethane production to rise even higher, to 1.8 million b/d by 2018, according to the latest Short-Term Energy Outlook.
Ethane is primarily consumed as a petrochemical feedstock, and through steam cracking is converted to ethylene, which serves as the starting molecule for various types of plastics and consumer products. Ethylene cracker capacity has grown in recent years, going from 92,000 b/d in the first quarter of 2015 to 320,000 b/d during the second quarter of 2017, and additional domestic cracker projects are underway. Both ExxonMobil and Chevron Phillips have new projects slated to start up during the second half of 2017. Both projects are located in Texas and each have a capacity of 1.5 million metric tons per year (mt/y). In addition, the Indorama Ventures Olefins’ restart project in Carlyss, Louisiana, will add about 370 mt/y capacity during the fourth quarter.
U.S. exports of ethane have also increased substantially, from an average of 37,750 b/d in 2014 to 94,700 b/d in 2016. In May, exports reached their highest level at 191,000 b/d.
In March 2016, the first U.S. maritime ethane export terminal shipped its first ethane cargo to Rafnes, Norway. This facility, located at Marcus Hook, Pennsylvania, has a capacity of 35,000 b/d. In September 2016, the terminal at Morgan Point, Texas, with an export capacity of 200,000 b/d, shipped its first cargo to Rafnes, Norway.
Overview:
(For the Week Ending Wednesday, August 23, 2017)
- Natural gas spot price movements were mixed this report week (Wednesday, August 16 to Wednesday, August 23). The Henry Hub spot price rose from $2.89 per million British thermal units (MMBtu) last Wednesday to $2.92/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the September 2017 contract price rose 4¢ from $2.890/MMBtu last Wednesday to $2.928/MMBtu yesterday.
- Net injections to working gas totaled 43 billion cubic feet (Bcf) for the week ending August 18. Working natural gas stocks are 3,125 Bcf, which is 7% less than the year-ago level and 1% more than the five-year (2012–16) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 8¢, averaging $7.03/MMBtu for the week ending August 23. The price of natural gasoline, ethane, butane, and isobutane rose by 1%, 2%, 5%, and 2%, respectively. The price of propane remained flat week over week.
- According to Baker Hughes, for the week ending Friday, August 18, the natural gas rig count increased by 1 to 182. The number of oil-directed rigs fell by 5 to 763. The number of miscellaneous rigs increased to one. The total rig count decreased by 3, and it now stands at 946.
Prices/Supply/Demand:
Price movements mixed for fourth week in a row. This report week (Wednesday, August 16 to Wednesday, August 23), the Henry Hub spot price rose 3¢ from $2.89/MMBtu last Wednesday to $2.92/MMBtu yesterday. The Henry Hub spot price reached a high of $3.01/MMBtu on Tuesday before falling 9¢ to yesterday’s price for delivery today. The majority of the Lower 48 states are expected to experience cooler temperatures today compared to yesterday, according to NOAA data. At the Chicago Citygate, prices decreased only 1¢ from $2.85/MMBtu last Wednesday to $2.84/MMBtu yesterday.
In California, prices at key natural gas trading hubs are higher than the Henry Hub price, the national benchmark for natural gas spot prices. Prices at PG&E Citygate in Northern California rose 9¢, up from $3.22/MMBtu last Wednesday to $3.31/MMBtu yesterday. The price at SoCal Citygate increased 44¢ from $2.76/MMBtu last Wednesday to $3.20/MMBtu yesterday. According to EIA’s Southern California Daily Energy Report, there was a net withdrawal of 90 million cubic feet (MMcf) from Southern California Gas Company (SoCalGas) storage facilities on Tuesday. There was a net injection of 280 MMcf yesterday.
Northeast prices mixed with temperatures and takeaway capacity. At the Algonquin Citygate, which serves Boston-area consumers, day-ahead prices went down 21¢ from $2.47/MMBtu last Wednesday to $2.26/MMBtu yesterday. Temperatures today in New England are expected to be much cooler than yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York, prices increased 21¢ from $2.32/MMBtu last Wednesday to $2.53/MMBtu yesterday.
Tennessee Zone 4 Marcellus spot prices decreased 11¢ from $1.77/MMBtu last Wednesday to $1.66/MMBtu yesterday, and they have averaged $1.21/MMBtu below the Henry Hub price for the week. Prices at Dominion South in northwest Pennsylvania fell 5¢ from $1.79/MMBtu last Wednesday to $1.74/MMBtu yesterday. Over the past few years, several Appalachian pipeline projects have reduced the natural gas spot price discount at regional hubs to the Henry Hub.
Production is flat, and imports rise. According to data from PointLogic Energy, the average total supply of natural gas remained the same as the previous report week, averaging 78.7 Billion cubic feet per day (Bcf/d). Dry natural gas production remained constant week over week. Average net imports from Canada increased by 7% from last week.
Overall demand rises. Total U.S. consumption of natural gas rose by 4% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation climbed by 6% week over week. Industrial sector consumption stayed constant, averaging 19.5 Bcf/d. In the residential and commercial sectors, consumption increased by 5%. Natural gas exports to Mexico increased 2%.
U.S. LNG exports flat week over week. Three vessels (combined LNG-carrying capacity of 11.0 Bcf) departed Sabine Pass last week (Thursday to Wednesday), and one vessel (LNG-carrying capacity 3.6 Bcf) was loading at the terminal on Wednesday, August 23.
Storage:
Weekly net injections are below five-year average. Net injections into storage totaled 43 Bcf, compared with the five-year (2012–16) average net injection of 53 Bcf and last year's net injections of 12 Bcf during the same week. This week’s smaller-than-average net injections primarily resulted from increased cooling demand for natural gas because of warmer temperatures in the South Central region. Working gas stocks total 3,125 Bcf, which is 45 Bcf more than the five-year average and 223 Bcf less than last year at this time.
Net withdrawals from storage are reported in the South Central region for the sixth week in a row. This week marks the 10th week in row that net withdrawals were reported for salt facilities in the South Central region, totaling 9 Bcf this week. Working gas levels at nonsalt facilities in the the South Central region declined by 4 Bcf. The South Central nonsalt region has not reported a net injection since the storage week ending July 7.
So far in the 2017 refill season, net injections into working gas storage are lower than the five-year average in most regions of the Lower 48 states. Net injections into working gas totaled 1,074 Bcf since March 31, 2017—the traditional beginning of the refill season—compared with the five-year average of 1,294 Bcf over the same period. Smaller-than-average net injections to date during the 2017 injection season are the result of high electric sector demand (that was coupled with warmer-than-normal temperatures on average), relatively high levels of natural gas exports, and storage levels that were already above average at the start of the refill season. The East and Mountain regions are the only regions where net injections have exceeded the five-year average. Cumulative net injections during the 2016 refill season in the Lower 48 states totaled 870 Bcf by this time last year, which was also characterized by unusually high storage levels at the start of the 2016 refill season.
The January 2018 futures price continues trading at a premium over the current spot price. During the most recent storage week, the average natural gas spot price at the Henry Hub was $2.91/MMBtu, while the Nymex futures price of natural gas for delivery in January 2018 averaged $3.28/MMBtu, a difference of 37¢. The premium was 51¢ a year ago. Also, the average natural gas spot price at the Henry Hub was 3¢ lower than the front-month futures price at the Nymex. Last year at this time, the spot price was 11¢ higher than the front-month contract.
Reported net implied flows into storage were within the range of analysts’ expectations. According to the Bloomberg survey of natural gas analysts, estimates of net injections to working natural gas storage ranged from 37 Bcf to 50 Bcf with a median of 47 Bcf. Prices on the futures contract for September delivery rose 1¢/MMBtu to $2.98/MMBtu with 285 contracts traded at the release of the Weekly Natural Gas Storage Report. Prices varied close to that level in subsequent trading.
Temperatures were close to normal, on average, with significantly warmer temperatures in the southern regions of the Lower 48 states during the week. Temperatures in the Lower 48 states averaged 74 degrees Fahrenheit (°F), the same as the normal and 5°F lower than last year at this time. Temperatures were within 2°F of the normal level in most regions during the storage week. Temperatures in the South Atlantic, East, and West South Central Census divisions ranged between 78° F and 83°F, on average, close to normal levels for the week. These warm temperatures likely contributed to cooling demand for natural gas and also contributed to the net withdrawals from storage reported in the South Central region.
See also:
| Spot Prices ($/MMBtu) | Thu, 17-Aug |
Fri, 18-Aug |
Mon, 21-Aug |
Tue, 22-Aug |
Wed, 23-Aug |
|---|---|---|---|---|---|
| Henry Hub |
2.88 |
2.89 |
2.98 |
3.01 |
2.92 |
| New York |
2.65 |
2.94 |
3.15 |
2.47 |
2.53 |
| Chicago |
2.82 |
2.85 |
2.88 |
2.94 |
2.84 |
| Cal. Comp. Avg.* |
2.85 |
2.86 |
2.95 |
3.02 |
2.98 |
| Futures ($/MMBtu) | |||||
| September Contract | 2.929 |
2.893 |
2.962 |
2.939 |
2.928 |
| October Contract |
2.966 |
2.930 |
2.992 |
2.968 |
2.960 |
| *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: (8/17/17 - 8/23/17) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 82.0 |
82.3 |
80.5 |
| Dry production | 72.8 |
73.0 |
71.7 |
| Net Canada imports | 5.9 |
5.5 |
6.2 |
| LNG pipeline deliveries | 0.1 |
0.0 |
0.3 |
| Total supply | 78.7 |
78.6 |
78.2 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (8/17/17 - 8/23/17) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 62.3 |
60.0 |
61.3 |
| Power | 35.6 |
33.5 |
35.2 |
| Industrial | 19.5 |
19.6 |
19.3 |
| Residential/commercial | 7.2 |
6.8 |
6.7 |
| Mexico exports | 4.3 |
4.3 |
4.3 |
| Pipeline fuel use/losses | 6.7 |
6.4 |
6.6 |
| LNG pipeline receipts | 1.9 |
1.8 |
0.8 |
| Total demand | 75.2 |
72.5 |
73.0 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Fri, August 18, 2017 |
Change from |
||
last week |
last year |
||
| Oil rigs | 763 |
-0.7% |
87.9% |
| Natural gas rigs | 182 |
0.6% |
119.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Fri, August 18, 2017 |
Change from |
||
last week |
last year |
||
| Vertical | 66 |
-8.3% |
3.1% |
| Horizontal | 799 |
-0.2% |
109.2% |
| Directional | 81 |
6.6% |
80.0% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2017-08-18 |
2017-08-11 |
change |
|
| East | 728 |
701 |
27 |
|
| Midwest | 821 |
798 |
23 |
|
| Mountain | 206 |
204 |
2 |
|
| Pacific | 296 |
292 |
4 |
|
| South Central | 1,074 |
1,087 |
-13 |
|
| Total | 3,125 |
3,082 |
43 |
|
| Source: U.S. Energy Information Administration | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (8/18/16) |
5-year average (2012-2016) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 773 |
-5.8 |
737 |
-1.2 |
|
| Midwest | 873 |
-6.0 |
804 |
2.1 |
|
| Mountain | 219 |
-5.9 |
184 |
12.0 |
|
| Pacific | 310 |
-4.5 |
331 |
-10.6 |
|
| South Central | 1,173 |
-8.4 |
1,025 |
4.8 |
|
| Total | 3,348 |
-6.7 |
3,080 |
1.5 |
|
| Source: U.S. Energy Information Administration | |||||
| Temperature – heating & cooling degree days (week ending Aug 17) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 2 |
-2 |
2 |
34 |
-2 |
-51 |
||
| Middle Atlantic | 1 |
-2 |
1 |
45 |
-5 |
-61 |
||
| E N Central | 5 |
0 |
5 |
39 |
-8 |
-39 |
||
| W N Central | 5 |
1 |
5 |
43 |
-18 |
-24 |
||
| South Atlantic | 0 |
0 |
0 |
104 |
13 |
-18 |
||
| E S Central | 0 |
0 |
0 |
94 |
6 |
-14 |
||
| W S Central | 0 |
0 |
0 |
129 |
7 |
6 |
||
| Mountain | 2 |
-3 |
2 |
67 |
-3 |
-17 |
||
| Pacific | 1 |
-2 |
1 |
43 |
-1 |
-26 |
||
| United States | 2 |
-1 |
2 |
68 |
0 |
-28 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-Day Mean ending Aug 17, 2017
Source: NOAA National Weather Service
Deviation between average and normal (°F)
7-Day Mean ending Aug 17, 2017
Source: NOAA National Weather Service
