In the News:
Ongoing pipeline maintenance limits SoCalGas’s ability to import natural gas into Southern California
As of August 16, 2018, several planned and unplanned maintenance events were limiting Southern California Gas Company’s (SoCalGas) ability to import natural gas into the Southern California region through key corridors, or zones.
SoCalGas’s two largest import corridors—the Northern Zone and the Southern Zone—are the primary zones affected by the ongoing maintenance activity. At full operating capacity, the Northern Zone and Southern Zone account for 1.6 billion cubic feet per day (Bcf/d) and 1.2 Bcf/d of regional pipeline import capacity, respectively, out of a total pipeline import capacity of 3.9 Bcf/d, according to SoCalGas.
Since September 2017, SoCalGas’s Northern Zone capacity has been limited to about 870 million cubic feet per day (MMcf/d), or approximately 55% of full operating capacity, because of outages on several pipelines operated by SoCalGas: Line 3000, Line 4000, and Line 235-2. Although the unplanned remediation work on Line 3000, which has been underway since 2016, is expected to be completed by mid-September, total Northern Zone capacity will be indefinitely limited to 870 MMcf/d because of ongoing restricted operation on Line 4000 and Line 235-2, according to SoCalGas’s maintenance logs.
Since March 10, 2018, SoCalGas’s Southern Zone capacity has been limited to an average of 784 MMcf/d, or about 65% of full operating capacity, because of ongoing system operating conditions. These conditions include voluntary pressure reductions on Line 2000 (operated by SoCalGas) to improve safety conditions as well as the right-of–way expiration (see the March 28, 2018 Southern Zone Capacity Reduction notice on ENVOY under Notices/Critical) for a portion of Line 2000. None of the pipeline maintenance issues in the Southern Zone have an estimated end date, according to SoCalGas.
Although the resulting reduction of operational flexibility poses a challenge to SoCalGas as it simultaneously refills its natural gas storage facilities ahead of peak winter demand for natural gas space heating needs and meets incremental, space cooling-related demand from electric-power generators, natural gas storage inventory levels as of August 13 were 67.2 Bcf, or 11.9 Bcf higher than at the same time last year. However, this level is 22.6 Bcf lower than the 2013–17 average because of storage capacity limitations imposed after a leak that was discovered at the Aliso Canyon storage field in October 2015. Since July 2018, total storage capacity in Southern California has been 83.4 Bcf.
So far this injection season—traditionally April 1 through October 31, when natural gas is put into underground storage in advance of peak winter demand—SoCalGas’s daily average net injections were 146 MMcf/d as of August 13 compared to 116 MMcf/d over the same time period last year, an increase of about 25%. Meanwhile, overall system sendout on the SoCalGas system decreased by 4% over the same time period. Despite this overall decrease in demand, temporary periods of weather-driven demand increases have coincided with reduced operational flexibility, which has resulted in unusually high price spikes at the SoCal Citygate.
EIA provides a daily summary of key energy conditions, as well as occasional commentary and analysis on notable market conditions in Southern California, in its Southern California Daily Energy Report.
Overview:
(For the Week Ending Wednesday, August 8, 2018)
- Natural gas spot prices rose at most locations this report week (Wednesday, August 8 to Wednesday, August 15). Henry Hub spot prices rose from $2.97 per million British thermal units (MMBtu) last Wednesday to $3.01/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the September 2018 contract price fell 1¢ from $2.949/MMBtu last Wednesday to $2.940/MMBtu yesterday.
- Net injections to working gas totaled 33 billion cubic feet (Bcf) for the week ending August 10. Working natural gas stocks are 2,387 Bcf, which is 22% lower than the year-ago level and 20% lower than the five-year (2013–17) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 6¢, averaging $8.95/MMBtu for the week ending August 15. The price of natural gasoline, butane, and isobutane fell by 2%, 2%, and 1%, respectively. The price of ethane rose by 1%. The price of propane remained flat week over week.
- According to Baker Hughes, for the week ending Tuesday, August 7, the natural gas rig count increased by 3 to 186. The number of oil-directed rigs rose by 10 to 869. The total rig count increased by 13, and it now stands at 1,057.
Prices/Supply/Demand:
Price trends vary across the Lower 48 states. This report week (Wednesday, August 8 to Wednesday, August 15), Henry Hub spot prices rose 4¢ from $2.97/MMBtu last Wednesday to $3.01/MMBtu yesterday. At the Chicago Citygate, prices decreased 6¢ from $3.01/MMBtu last Wednesday to $2.95/MMBtu yesterday.
Prices at PG&E Citygate in Northern California rose 3¢, up from $3.45/MMBtu last Wednesday to $3.48/MMBtu yesterday. Prices at SoCal Citygate decreased $6.28 from $14.17/MMBtu last Wednesday to $7.89/MMBtu yesterday. Temperatures on the West Coast generally trended down as the report week progressed, lessening demand in the supply-constrained region of Southern California. This decreased demand allowed for six consecutive days of net flow of natural gas into storage, which has not happened since the beginning of July of this year.
Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $2.10/MMBtu last Wednesday, 87¢ lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $1.95/MMBtu, $1.06 lower than the Henry Hub price.
Northeast prices increase. At the Algonquin Citygate, which serves Boston-area consumers, prices went up 88¢ from $3.26/MMBtu last Wednesday to $4.14/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 7¢ from $3.07/MMBtu last Wednesday to $3.14/MMBtu yesterday. NGI notes that two maintenance events were to begin today on the Algonquin Gas Transmission mainline that could affect flows in the coming weeks.
Tennessee Zone 4 Marcellus spot prices increased 8¢ from $2.45/MMBtu last Wednesday to $2.53/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 5¢ from $2.59/MMBtu last Wednesday to $2.64/MMBtu yesterday.
Nymex prices essentially flat. At the Nymex, the price of the September 2018 contract decreased 1¢, from $2.949/MMBtu last Wednesday to $2.940/MMBtu yesterday. The price of the 12-month strip averaging September 2018 through August 2019 futures contracts climbed 1¢ to $2.900/MMBtu.
Total supply remains flat as dry production increases. According to data from PointLogic Energy, the average total supply of natural gas remained the same as in the previous report week, averaging 87.3 Bcf/d. Dry natural gas production grew by 1% compared with the previous report week. Average net imports from Canada decreased by 6% from last week.
Demand falls. Total U.S. consumption of natural gas fell by 3% compared with the previous report week, according to data from PointLogic Energy. Natural gas consumed for power generation declined by 4% week over week as average temperatures along the Gulf Coast and southern border fell. Industrial sector consumption stayed constant, averaging 19.7 Bcf/d. In the residential and commercial sectors, consumption declined by 1%. Natural gas exports to Mexico decreased 3%.
U.S. liquefied natural gas (LNG) exports increase week over week. Six LNG vessels (four from Sabine Pass and two from Cove Point) with a combined LNG-carrying capacity of 21.8 Bcf departed the United States from August 9 through August 15. Two LNG tankers (combined LNG-carrying capacity 7.3 Bcf) were loading at Sabine Pass on Wednesday, August 15.
Storage:
Net injections are lower than the five-year average for the seventh week in a row. Net injections into storage totaled 33 Bcf for the week ending August 10, compared with the five-year (2013–17) average net injections of 56 Bcf and last year's net injections of 49 Bcf during the same week. Working gas stocks totaled 2,387 Bcf, which is 595 Bcf lower than the five-year average and 687 Bcf lower than last year at this time.
Working gas stocks are lower than the five-year range for the second week in a row. The average rate of net injections into storage is 19% lower than the five-year average so far in the 2018 refill season. If working gas stocks match the five-year average rate of injections of 10.1 Bcf/d for the remainder of the refill season, inventories will total 3,220 Bcf on October 31, which is 340 Bcf lower than the five-year low of 3,560 Bcf. In the Lower 48 states, total working gas are currently 24 Bcf lower than the five-year range in the East region and 70 Bcf lower than the five-year range in the Midwest.The South Central region posted working gas stocks that are 29 Bcf higher than the bottom of the region’s five-year range, and its nonsalt facilities are 51 Bcf higher than its lower bound. Total working gas stocks in the Lower 48 states are now 105 Bcf lower than the five-year range.
Despite historically low storage inventories, 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 net injections into working gas. During the most recent storage week, the average natural gas spot price at the Henry Hub averaged $2.92/MMBtu while the Nymex futures price of natural gas for delivery in January 2019 averaged $3.12/MMBtu, 21¢/MMBtu higher than the spot price. A year ago, the January contract was 41¢/MMBtu higher than the spot price.
Reported net injections into storage are close to the median 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 17 Bcf to 38 Bcf, with a median estimate of 30 Bcf. At the 10:30 a.m. release of the Weekly Natural Gas Storage Report (WNGSR), the price of the Nymex futures contract for September delivery at the Henry Hub fell 2¢/MMBtu to $2.90/MMBtu, with 1,164 trades executed. Prices remained close to this level in subsequent trading.
Temperatures are in the higher-than-normal range for the storage week. Temperatures in the Lower 48 states averaged 78 degrees Fahrenheit (°F), 3°F higher than normal and 5°F higher than last year at this time. Temperatures were 2°F higher than the level reported for the previous week.
See also:
| Spot Prices ($/MMBtu) | Thu, 09-Aug |
Fri, 10-Aug |
Mon, 13-Aug |
Tue, 14-Aug |
Wed, 15-Aug |
|---|---|---|---|---|---|
| Henry Hub |
2.98 |
2.92 |
2.92 |
2.98 |
3.01 |
| New York |
3.01 |
2.94 |
3.10 |
3.14 |
3.14 |
| Chicago |
2.93 |
2.83 |
2.93 |
2.94 |
2.95 |
| Cal. Comp. Avg.* |
5.11 |
3.94 |
3.47 |
3.45 |
3.19 |
| Futures ($/MMBtu) | |||||
| September contract | 2.955 |
2.944 |
2.930 |
2.959 |
2.940 |
| October contract |
2.959 |
2.949 |
2.936 |
2.966 |
2.948 |
| *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: (8/9/18 - 8/15/18) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 92.6 |
92.1 |
82.5 |
| Dry production | 82.0 |
81.5 |
73.0 |
| Net Canada imports | 5.3 |
5.6 |
5.5 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.0 |
| Total supply | 87.3 |
87.1 |
78.5 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (8/9/18 - 8/15/18) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 62.7 |
64.4 |
58.8 |
| Power | 36.0 |
37.6 |
32.7 |
| Industrial | 19.7 |
19.8 |
19.7 |
| Residential/commercial | 6.9 |
7.0 |
6.4 |
| Mexico exports | 4.7 |
4.9 |
4.4 |
| Pipeline fuel use/losses | 6.7 |
6.9 |
6.3 |
| LNG pipeline receipts | 3.5 |
3.3 |
1.8 |
| Total demand | 77.6 |
79.5 |
71.4 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Tue, August 07, 2018 |
Change from |
||
last week |
last year |
||
| Oil rigs | 869 |
1.2% |
13.2% |
| Natural gas rigs | 186 |
1.6% |
2.8% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, August 07, 2018 |
Change from |
||
last week |
last year |
||
| Vertical | 69 |
1.5% |
-4.2% |
| Horizontal | 924 |
1.3% |
15.4% |
| Directional | 64 |
0.0% |
-15.8% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2018-08-10 |
2018-08-03 |
change |
|
| East | 592 |
575 |
17 |
|
| Midwest | 603 |
579 |
24 |
|
| Mountain | 151 |
148 |
3 |
|
| Pacific | 240 |
245 |
-5 |
|
| South Central | 801 |
807 |
-6 |
|
| Total | 2,387 |
2,354 |
33 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (8/10/17) |
5-year average (2013-2017) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 697 |
-15.1 |
694 |
-14.7 |
|
| Midwest | 794 |
-24.1 |
759 |
-20.6 |
|
| Mountain | 204 |
-26.0 |
183 |
-17.5 |
|
| Pacific | 292 |
-17.8 |
320 |
-25.0 |
|
| South Central | 1,088 |
-26.4 |
1,026 |
-21.9 |
|
| Total | 3,074 |
-22.3 |
2,982 |
-20.0 |
|
| Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report" | |||||
| Temperature – heating & cooling degree days (week ending Aug 09) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 0 |
-2 |
-3 |
90 |
47 |
59 |
||
| Middle Atlantic | 0 |
-3 |
-4 |
91 |
34 |
55 |
||
| E N Central | 0 |
-4 |
-10 |
74 |
20 |
54 |
||
| W N Central | 0 |
-3 |
-12 |
76 |
9 |
48 |
||
| South Atlantic | 0 |
0 |
0 |
107 |
12 |
18 |
||
| E S Central | 0 |
0 |
0 |
100 |
7 |
29 |
||
| W S Central | 0 |
0 |
0 |
126 |
2 |
14 |
||
| Mountain | 0 |
-2 |
-4 |
92 |
19 |
18 |
||
| Pacific | 0 |
-2 |
0 |
81 |
34 |
5 |
||
| United States | 0 |
-2 |
-4 |
93 |
21 |
32 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-Day Mean ending Aug 09, 2018
Source: NOAA National Weather Service
Deviation between average and normal (°F)
7-Day Mean ending Aug 09, 2018
Source: NOAA National Weather Service
