In the News:
EIA updates heat content values for hydrocarbon gas liquids
In the October 2019 release of the Monthly Energy Review, the U.S. Energy Information Administration (EIA) updated the conversion factors it uses and publishes for hydrocarbon gas liquids (HGL) products. These conversion factors allow data users to convert volumetric quantities of HGL into heat content equivalents―from barrels to million British thermal units (MMBtu). EIA’s previous conversion factors date back to 1942, with the exception of the factor for natural gasoline (e.g., pentanes plus), which was established in 1956 by the U.S. Bureau of Mines. EIA revised the new conversion factors to be more comparable to industry standards. They now generally differ by less than 1% from those estimated by the GPA Midstream Association, a trade group that represents the natural gas midstream industry and helps set technical standards.
EIA’s update of these conversion factors largely reflects changes in natural gas processing and fractionation in the United States. In recent decades, the process of separating liquid products from the natural gas stream in the United States has relied increasingly more on cryogenics, or the separation of products by temperature, and less on chemical separation. As a result, U.S. HGL are typically purer, containing a lower percentage of contaminants and other hydrocarbon molecules. Measurement equipment has also improved with advances in technology.
With EIA’s new conversion factors, ethane, which is volumetrically the largest HGL product produced at natural gas processing plants and fractionators, has a lower heat content per barrel. In the 1940s in the United States, ethane contained a greater share of propane and butane, which are both more energy-dense than ethane. Consequently, on a heat-content basis, EIA’s reported ethane prices are now more expensive than previously reported by about $0.25/MMBtu in recent months, down from being $0.50/MMBtu more expensive late last year. Ethane consumption as a U.S. petrochemical feedstock has nonetheless been growing in recent years and months, as it is still relatively inexpensive and plentiful in supply compared with feedstock alternatives.
Conversion factors are now available for both alkanes (HGL products ending in –ane, such as ethane, propane, etc.) and for olefins (HGL products ending in –ene, such as ethylene, propylene, etc.). EIA previously used the same conversion factor for both products.
Overview:
(For the week ending Wednesday, November 6, 2019)
- Natural gas spot prices fell at most locations this report week (Wednesday, November 6 to Wednesday, November 13). Henry Hub spot prices fell from $2.78 per million British thermal units (MMBtu) last Wednesday to $2.62/MMBtu yesterday.
- At the New York Mercantile Exchange (Nymex), the price of the December 2019 contract decreased 23¢, from $2.828/MMBtu last Wednesday to $2.600/MMBtu yesterday. The price of the 12-month strip averaging December 2019 through November 2020 futures contracts declined 8¢/MMBtu to $2.487/MMBtu.
- Net injections to working gas totaled 3 billion cubic feet (Bcf) for the week ending November 8. Working natural gas stocks are 3,732 Bcf, which is 15% more than the year-ago level and equal to the five-year (2014–18) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 4¢/MMBtu, averaging $5.69/MMBtu for the week ending November 13. The price of ethane and isobutane each fell by 3%. The price of natural gasoline and propane rose by 1%, and butane rose by 10%.
- According to Baker Hughes, for the week ending Tuesday, November 5, the natural gas rig count remained flat at 130. The number of oil-directed rigs fell by 7 to 684. The total rig count decreased by 5, and it now stands at 817.
Prices/Supply/Demand:
Prices at major hubs decline despite cold weather. This report week (Wednesday, November 6 to Wednesday, November 13), the Henry Hub spot price fell 16¢ from $2.78/MMBtu last Wednesday to a low of $2.62/MMBtu yesterday. Temperatures were cooler than normal east of the Rocky Mountains and warmer than normal west of the Rockies. At the Chicago Citygate, the price decreased 49¢ from $2.98/MMBtu last Wednesday to a low of $2.49/MMBtu yesterday.
Northeast prices are volatile with onset of cold temperatures and force majeure events. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 85¢ from a low of $3.08/MMBtu last Wednesday to $3.93/MMBtu yesterday. It reached a high of $6.38/MMBtu on Tuesday because of forecasts for cold weather. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 57¢ from a low of $2.70/MMBtu last Wednesday to $3.27/MMBtu yesterday after reaching a high of $5.60/MMBtu on Tuesday.
Prices at supply hubs in the Northeast, however, declined as a force majeure decreased natural gas deliverability out of the Marcellus production region. The Tennessee Zone 4 Marcellus spot price decreased 37¢ from $2.42/MMBtu last Wednesday to $2.05/MMBtu yesterday while the price at Dominion South in southwest Pennsylvania fell 32¢―from $2.46/MMBtu last Wednesday to $2.14/MMBtu yesterday. Eastbound flows on the Texas Eastern Transmission pipeline (TETCO) were reduced by approximately 0.4 Bcf/d yesterday because of a force majeure at a compressor station in Entriken, Pennsylvania (100 miles west of Harrisburg).
In addition, the Iroquois Gas Transmission System declared a force majeure on Tuesday at a compressor station in Dover, New York, located approximately 80 miles north of New York City. The event restricted southbound flows on the system.
California prices are mixed. The price at PG&E Citygate in Northern California fell 36¢, down from $3.44/MMBtu last Wednesday to a low of $3.08/MMBtu yesterday. The price at SoCal Citygate in Southern California increased 79¢ from a low of $3.48/MMBtu last Wednesday to $4.27/MMBtu yesterday.
Permian Basin price discount to the Henry Hub narrows. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $0.99/MMBtu last Wednesday, $1.79/MMBtu lower than Henry Hub price. Yesterday, the price at the Waha Hub averaged $1.84/MMBtu, 78¢/MMBtu lower than Henry Hub price. Mean daily temperatures in Texas and eastern New Mexico were 18 degrees to 24 degrees Fahrenheit (°F) lower than normal at the end of the report week, increasing demand and placing upward pressure on prices.
Supply rises. According to data from IHS Markit, the average total supply of natural gas rose by 1% compared with the previous report week. Dry natural gas production remained constant week over week. Average net imports from Canada increased by 19% from last week as imports from Canada into the Iroquois pipeline at Waddington in upstate New York rose more than 1 Bcf/d during the report week. According to Genscape, the pipeline has been flowing at full capacity―1.15 Bcf/d―at the Canada-United States border since Tuesday.
Demand rises significantly with cold weather, hitting a new consumption record on Tuesday. Total U.S. consumption (including exports) of natural gas rose by 10% compared with the previous report week, according to data from IHS Markit, reaching an all-time high for November of 126 Bcf/d on Tuesday, approximately 15 Bcf higher than the previous record set on November 27, 2018. Natural gas consumed for power generation climbed by 6% week over week. Industrial sector consumption increased by 3% week over week. In the residential and commercial sectors, consumption increased by 20%. Natural gas exports to Mexico were the same as last week, averaging 5.2 Bcf/d.
U.S. LNG exports increase over week. Thirteen liquefied natural gas (LNG) vessels (eight from Sabine Pass, two from Corpus Christi, and one each from Cove Point, Cameron, and Freeport) with a combined LNG-carrying capacity of 47 Bcf departed the United States between November 7 and November 13, according to shipping data compiled by Bloomberg. One vessel was loading at the Sabine Pass terminal on Wednesday.
Storage:
Net injections into storage totaled 3 Bcf for the week ending November 8, compared with the five-year (2014–18) average net injections of 30 Bcf and last year's net injections of 42 Bcf during the same week. Working gas stocks totaled 3,732 Bcf, which is 2 Bcf more than the five-year average and 491 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 withdrawals of 15 Bcf to net injections of 9 Bcf, with a median estimate of net withdrawals of 2 Bcf.
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, 07-Nov |
Fri, 08-Nov |
Mon, 11-Nov |
Tue, 12-Nov |
Wed, 13-Nov |
|---|---|---|---|---|---|
| Henry Hub |
2.84 |
2.82 |
2.69 |
2.73 |
2.62 |
| New York |
2.90 |
2.38 |
4.26 |
5.60 |
3.27 |
| Chicago |
2.86 |
2.71 |
2.67 |
2.63 |
2.49 |
| Cal. Comp. Avg.* |
2.90 |
2.79 |
2.74 |
2.78 |
2.71 |
| Futures ($/MMBtu) | |||||
| December contract | 2.772 |
2.789 |
2.637 |
2.621 |
2.600 |
| January contract |
2.859 |
2.873 |
2.728 |
2.714 |
2.692 |
| *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: (11/7/19 - 11/13/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 107.6 |
107.4 |
98.2 |
| Dry production | 95.0 |
95.0 |
87.8 |
| Net Canada imports | 5.4 |
4.5 |
3.9 |
| LNG pipeline deliveries | 0.2 |
0.1 |
0.1 |
| Total supply | 100.6 |
99.5 |
91.8 |
|
Source: IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (11/7/19 - 11/13/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 81.6 |
74.0 |
82.6 |
| Power | 27.9 |
26.2 |
26.7 |
| Industrial | 21.9 |
21.3 |
24.7 |
| Residential/commercial | 31.9 |
26.5 |
31.2 |
| Mexico exports | 5.2 |
5.2 |
4.8 |
| Pipeline fuel use/losses | 6.9 |
6.7 |
6.6 |
| LNG pipeline receipts | 7.1 |
7.3 |
4.0 |
| Total demand | 100.8 |
93.3 |
98.1 |
|
Source: IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, November 05, 2019 |
Change from |
||
last week |
last year |
||
| Oil rigs | 684 |
-1.0% |
-22.8% |
| Natural gas rigs | 130 |
0.0% |
-33.3% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, November 05, 2019 |
Change from |
||
last week |
last year |
||
| Vertical | 51 |
-1.9% |
-29.2% |
| Horizontal | 710 |
-1.0% |
-24.1% |
| Directional | 56 |
5.7% |
-24.3% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2019-11-08 |
2019-11-01 |
change |
|
| East | 932 |
932 |
0 |
|
| Midwest | 1,106 |
1,109 |
-3 |
|
| Mountain | 207 |
207 |
0 |
|
| Pacific | 290 |
292 |
-2 |
|
| South Central | 1,197 |
1,189 |
8 |
|
| Total | 3,732 |
3,729 |
3 |
|
|
Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (11/8/18) |
5-year average (2014-2018) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 834 |
11.8 |
904 |
3.1 |
|
| Midwest | 989 |
11.8 |
1,085 |
1.9 |
|
| Mountain | 181 |
14.4 |
213 |
-2.8 |
|
| Pacific | 266 |
9.0 |
328 |
-11.6 |
|
| South Central | 970 |
23.4 |
1,200 |
-0.3 |
|
| Total | 3,241 |
15.1 |
3,730 |
0.1 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Nov 07) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 143 |
4 |
43 |
0 |
0 |
0 |
||
| Middle Atlantic | 145 |
15 |
53 |
0 |
0 |
0 |
||
| E N Central | 187 |
42 |
47 |
0 |
0 |
0 |
||
| W N Central | 204 |
48 |
40 |
0 |
0 |
0 |
||
| South Atlantic | 100 |
18 |
43 |
23 |
7 |
2 |
||
| E S Central | 118 |
35 |
53 |
0 |
-2 |
-2 |
||
| W S Central | 68 |
20 |
30 |
10 |
-2 |
-8 |
||
| Mountain | 145 |
4 |
14 |
5 |
2 |
2 |
||
| Pacific | 41 |
-24 |
18 |
0 |
-2 |
-4 |
||
| United States | 129 |
18 |
38 |
6 |
1 |
-1 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Nov 07, 2019
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Nov 07, 2019
Source: National Oceanic and Atmospheric Administration
