In the News:
The ethane price premium to natural gas has nearly tripled over the past three months
Ethane prices at Mont Belvieu, Texas, from August 1–28, 2018, averaged $2.38 per million British thermal units (MMBtu) higher than natural gas spot prices at the U.S. benchmark Henry Hub in Louisiana during that same period. This differential has nearly tripled since May 2018, when the ethane premium was 80¢/MMBtu.
Before 2013, ethane prices trended higher than natural gas prices. However, from about 2013 to 2016, when ethane supply exceeded demand, ethane spot prices were generally lower than Henry Hub natural gas spot prices. Since mid-2017, ethane prices have again been consistently higher than natural gas prices as domestic and foreign consumption of U.S. ethane has grown.
U.S. exports of ethane increased from marine export terminals that came online in 2016. According to EIA’s most recent Petroleum Supply Monthly data, U.S. exports of ethane averaged more than 280,000 b/d in May 2018, a year-on-year increase of 48%.
In addition, U.S. ethane demand growth has accelerated since the beginning of 2018, when new and expanded ethylene crackers began operations. These facilities convert ethane into ethylene, a compound used in the production of plastics, resins, and other chemicals. Chevron Philips Chemical began operation of its new Cedar Bayou, Texas cracker in March, and ExxonMobil began operations of its newly-built Baytown, Texas cracker at the end of July. Both facilities are close to the Mont Belvieu hydrocarbon gas liquids trading hub, where ethane spot prices are set.
The increased ethane demand in both global and domestic markets is expected to continue in the short term, and it has pushed production farther from demand centers, which has strained the capacity of existing pipeline and fractionation infrastructure. These infrastructure constraints have likely contributed to the increase in price.
Ethane is one of several natural gas plant liquids (NGPL) that are found in raw natural gas. Although heavier NGPL such as propane, butanes, and natural gasoline must be removed from raw natural gas before it is put into interstate pipelines, some ethane can be left (i.e., rejected) in pipeline-quality natural gas. The economics of rejecting ethane follow the ethane-to-natural-gas price differential, so when ethane prices are significantly higher than natural gas prices, producers achieve higher revenues by extracting ethane and selling it separately. As a result of rising U.S. ethane prices, ethane output from natural gas processing plants continues to grow, exceeding 1.7 million b/d in both April and May 2018.
Overview:
(For the Week Ending Wednesday, August 29, 2018)
- Natural gas spot prices fell at most locations this report week (Wednesday, August 22 to Wednesday, August 29). Henry Hub spot prices fell from $2.99 per million British thermal units (MMBtu) last Wednesday to $2.96/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the September 2018 contract expired yesterday at $2.895/MMBtu. The October 2018 contract price decreased to $2.863/MMBtu, down 8¢ Wednesday to Wednesday.
- Net injections to working gas totaled 70 billion cubic feet (Bcf) for the week ending August 24. Working natural gas stocks are 2,505 Bcf, which is 21% lower than the year-ago level and 19% lower than the five-year (2013–17) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 37¢, averaging $9.37/MMBtu for the week ending August 29. The price of natural gasoline, ethane, propane, butane, and isobutane all rose by 3%, 1%, 6%, 5%, and 6%, respectively.
- According to Baker Hughes, for the week ending Tuesday, August 21, the natural gas rig count decreased by 4 to 182. The number of oil-directed rigs fell by 9 to 860. The total rig count decreased by 13, and it now stands at 1,044.
Prices/Supply/Demand:
National benchmark spot price decreases with mixed temperatures. This report week (Wednesday, August 22 to Wednesday, August 29), Henry Hub spot prices for Thursday delivery decreased from $2.99/MMBtu last Wednesday to $2.96/MMBtu yesterday, a difference of 3¢. While delivery-day temperatures are expected to be warmer today in the Mid-Atlantic and Appalachian regions compared to last Thursday, temperatures across the Gulf Coast are expected to be similar to last Thursday, and temperatures across the Pacific Northwest and Upper Great Plains are expected to be cooler.
Price at key Midwest trading hub decreases with cooler weather. At the Chicago Citygate, prices for Thursday delivery decreased 13¢ from $2.85/MMBtu last Wednesday to $2.72/MMBtu yesterday. Temperatures across much of the Great Lakes region are expected to be slightly cooler today than last Thursday.
California citygate prices are mixed. Prices at SoCal Citygate for Thursday delivery increased 64¢ from $4.92/MMBtu last Wednesday to $5.56/MMBtu yesterday. Southern California Gas Company (SoCalGas) forecasted today’s demand to be 6% higher compared to last Thursday, leaving less natural gas available for injections. SoCalGas has been working to maximize storage injections ahead of peak winter demand in Southern California amid ongoing maintenance, which is expected to persist throughout the winter months. Prices at PG&E Citygate in Northern California fell 15¢, down from $3.34/MMBtu last Wednesday to $3.19/MMBtu yesterday.
Key Northeast prices increase with warmer weather. At the Algonquin Citygate, which serves Boston-area consumers, prices for Thursday delivery went up 69¢ from $2.86/MMBtu last Wednesday to $3.55/MMBtu yesterday. Temperatures in parts of New England are expected to average up to 15 degrees Fahrenheit (°F) warmer today than last Thursday, according to data from the National Oceanic and Atmospheric Administration. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 7¢ from $2.97/MMBtu last Wednesday to $3.04/MMBtu yesterday.
Appalachian prices decrease. Tennessee Zone 4 Marcellus spot prices decreased 25¢ from $2.61/MMBtu last Wednesday to $2.36/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania fell 3¢ from $2.65/MMBtu last Wednesday to $2.62/MMBtu yesterday.
Permian basin spot prices decline and are now at record lows compared to Henry Hub spot prices. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $1.97/MMBtu last Wednesday, $1.02 lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $1.27/MMBtu, $1.69 lower than Henry Hub prices. This decrease is the largest differential between Waha and Henry Hub prices since at least 2013, according to Natural Gas Intelligence. The previous record differential between the two prices was $1.42 in April 2018.
Futures price decreases. At the Nymex, the September 2018 contract expired yesterday at $2.895/MMBtu, down 6¢ from last Wednesday. The October 2018 contract decreased to $2.863/MMBtu, down 8¢ from last Wednesday to yesterday. The price of the 12-month strip averaging October 2018 through September 2019 futures contracts declined 7¢ to $2.801/MMBtu.
Overall supply is flat. According to data from PointLogic Energy, the average total supply of natural gas remained about the same as in the previous report week, averaging 88.2 Bcf/d. Dry natural gas production remained constant week over week. Average net imports from Canada increased by 5% from last week.
Overall demand is flat. Total U.S. consumption of natural gas was unchanged from the previous report week, averaging 62.3 Bcf/d according to data from PointLogic Energy. Natural gas consumed for power generation remained largely unchanged, averaging 35.0 Bcf/d. However, with mixed temperatures across the Lower 48 states, regional power demand varied; demand in the Northeast increased the most, averaging about 0.9 Bcf/d higher this week compared to last week, while demand in the West saw the largest declines, averaging about 0.7 Bcf/d lower this week compared to last week. Industrial sector consumption stayed constant, averaging 19.8 Bcf/d. In the residential and commercial sectors, consumption remained at last week's level, averaging 7.5 Bcf/d. Natural gas exports to Mexico decreased 2%.
U.S. LNG exports increase week over week. Six LNG vessels (five from Sabine Pass and one from Cove Point) with a combined LNG-carrying capacity of 22 Bcf departed the United States between August 23 and August 29. One LNG tanker (capacity 3.9 Bcf) was loading at the Cove Point terminal on Wednesday, August 29.
Freeport LNG, one of the four U.S. liquefaction facilities under construction, has moved up the expected in-service date for Train 1 to the second quarter of 2019 from the previously announced in-service date of September 2019. Project developers have received an approval from the Federal Energy Regulatory Commission to begin commissioning activities of Train 1 and common area utilities. Freeport LNG has three liquefaction production units—called trains—under construction, each with a nameplate capacity of 0.66 Bcf/d. The facility is located on Quintana Island, near Freeport, Texas.
Storage:
Net injections exceed the five-year average for the first time in nearly two months. Net injections into storage totaled 70 Bcf for the week ending August 24, compared with the five-year (2013–17) average net injections of 59 Bcf and last year's net injections of 32 Bcf during the same week. Working gas stocks totaled 2,505 Bcf, which is 588 Bcf lower than the five-year average and 646 Bcf lower than last year at this time.
Working gas stocks are lower than the five-year range for the fourth week in a row. The average rate of net injections into storage is 17% lower than the five-year average so far in the 2018 refill season. If the rate of injections into working gas matches the five-year average of 10.6 Bcf/d for the remainder of the refill season, inventories will total 3,227 Bcf on October 31, which is 333 Bcf lower than the five-year low of 3,560 Bcf. In the Lower 48 states, total working gas stocks are currently 25 Bcf lower than the five-year range in the East region and 79 Bcf lower than the five-year range in the Midwest. The South Central region posted working gas stocks that are 9 Bcf higher than the bottom of the region’s five-year range, and its nonsalt facilities are 36 Bcf higher than its lower bound. Total working gas stocks in the Lower 48 states are now 148 Bcf lower than the five-year range.
The average January 2019 futures contract price trades at a lower premium to the average spot price than last year at this time. Price differences between the spot price and the futures prices at the Nymex indicate limited economic incentives for injections into working gas. During the most recent storage week, the average natural gas spot price at the Henry Hub averaged $2.98/MMBtu, and the Nymex futures price of natural gas for delivery in January 2019 averaged $3.16/MMBtu, 18¢/MMBtu higher than the spot price. A year ago, the January contract was 33¢/MMBtu higher than the spot price.
Reported net injections into storage are at the high end of the range of analysts’ expections. According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas storage ranged from net injections of 58 Bcf to 70 Bcf, with a median estimate of 64 Bcf. At the 10:30 a.m. release of the Weekly Natural Gas Storage Report (WNGSR), the price of the Nymex futures contract for October delivery at the Henry Hub fell 2¢/MMBtu to $2.85/MMBtu, with 1,262 trades executed. Prices varied in subsequent trading, remaining close to $2.85/MMBtu.
Temperatures remain in the higher-than-normal range for the storage week. Temperatures in the Lower 48 states averaged 75 degrees °F, 1°F higher than normal and 1°F lower than last year at this time. Temperatures were 1°F lower than the level reported for the previous week.
See also:
| Spot Prices ($/MMBtu) | Thu, 23-Aug |
Fri, 24-Aug |
Mon, 27-Aug |
Tue, 28-Aug |
Wed, 29-Aug |
|---|---|---|---|---|---|
| Henry Hub |
2.96 |
2.96 |
2.95 |
2.93 |
2.96 |
| New York |
2.85 |
2.77 |
3.36 |
3.15 |
3.04 |
| Chicago |
2.85 |
2.82 |
2.85 |
2.80 |
2.72 |
| Cal. Comp. Avg.* |
2.73 |
2.67 |
2.67 |
2.70 |
2.72 |
| Futures ($/MMBtu) | |||||
| September contract | 2.964 |
2.917 |
2.876 |
2.852 |
2.895 |
| October contract |
2.953 |
2.913 |
2.869 |
2.845 |
2.863 |
| *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: (8/23/18 - 8/29/18) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 93.3 |
93.3 |
79.3 |
| Dry production | 82.7 |
82.6 |
70.5 |
| Net Canada imports | 5.4 |
5.1 |
5.7 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.0 |
| Total supply | 88.2 |
87.8 |
76.3 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (8/23/18 - 8/29/18) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 62.3 |
62.4 |
57.7 |
| Power | 35.0 |
35.1 |
30.7 |
| Industrial | 19.8 |
19.8 |
19.7 |
| Residential/commercial | 7.5 |
7.5 |
7.4 |
| Mexico exports | 4.6 |
4.7 |
4.1 |
| Pipeline fuel use/losses | 6.7 |
6.7 |
6.2 |
| LNG pipeline receipts | 3.1 |
3.3 |
1.9 |
| Total demand | 76.7 |
77.0 |
70.0 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Tue, August 21, 2018 |
Change from |
||
last week |
last year |
||
| Oil rigs | 860 |
-1.0% |
13.3% |
| Natural gas rigs | 182 |
-2.2% |
1.1% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, August 21, 2018 |
Change from |
||
last week |
last year |
||
| Vertical | 63 |
-3.1% |
-1.6% |
| Horizontal | 919 |
-0.3% |
15.5% |
| Directional | 62 |
-11.4% |
-22.5% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2018-08-24 |
2018-08-17 |
change |
|
| East | 640 |
613 |
27 |
|
| Midwest | 667 |
632 |
35 |
|
| Mountain | 157 |
153 |
4 |
|
| Pacific | 241 |
239 |
2 |
|
| South Central | 800 |
798 |
2 |
|
| Total | 2,505 |
2,435 |
70 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (8/24/17) |
5-year average (2013-2017) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 746 |
-14.2 |
737 |
-13.2 |
|
| Midwest | 837 |
-20.3 |
815 |
-18.2 |
|
| Mountain | 205 |
-23.4 |
189 |
-16.9 |
|
| Pacific | 300 |
-19.7 |
323 |
-25.4 |
|
| South Central | 1,062 |
-24.7 |
1,029 |
-22.3 |
|
| Total | 3,151 |
-20.5 |
3,093 |
-19.0 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | |||||
| Temperature – heating & cooling degree days (week ending Aug 23) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 2 |
-3 |
1 |
38 |
9 |
-9 |
||
| Middle Atlantic | 1 |
-2 |
1 |
53 |
10 |
-9 |
||
| E N Central | 4 |
-2 |
1 |
45 |
4 |
-6 |
||
| W N Central | 5 |
-2 |
1 |
43 |
-12 |
-7 |
||
| South Atlantic | 0 |
-1 |
0 |
98 |
11 |
-15 |
||
| E S Central | 0 |
0 |
0 |
85 |
2 |
-17 |
||
| W S Central | 0 |
0 |
0 |
129 |
11 |
-3 |
||
| Mountain | 7 |
-2 |
7 |
75 |
7 |
3 |
||
| Pacific | 0 |
-5 |
0 |
64 |
22 |
17 |
||
| United States | 2 |
-2 |
1 |
72 |
8 |
-5 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-Day Mean ending Aug 23, 2018
Source: NOAA National Weather Service
Deviation between average and normal (°F)
7-Day Mean ending Aug 23, 2018
Source: NOAA National Weather Service
