In the News:
Renewable natural gas is being used to decarbonize California’s transportation sector
Recent announcements by Southern California Gas (SoCalGas) indicate renewable natural gas (RNG) will increasingly contribute to efforts to decarbonize the state’s transportation fuel sector. RNG’s share of natural gas supply in California’s transportation sector grew from approximately 10% in 2013 to 70% in 2018, reaching more than 30 million diesel gallon equivalent, or about 45 million cubic feet per day, for the first time during the third quarter of 2018.
RNG, or biomethane, is a renewable fuel produced through the anaerobic decomposition of organic matter at facilities such as landfills, wastewater treatment facilities, and dairy farms. Biomethane is produced either through anaerobic digestion or via gasification, and purified in order to meet pipeline quality standards.
RNG has been increasingly consumed as part of California’s Low Carbon Fuel Standard (LCFS), which is part of California’s 2006 Global Warming Solutions Act (Assembly Bill-32), to reduce the carbon intensity of the state’s transportation fuel sector by 20% by 2030 relative to a 2010 baseline. Regardless of the origin of the natural gas at transportation fueling stations, the volume of biomethane injected into the pipeline system can be credited as either bio-compressed natural gas (bio-CNG) or bio-liquefied natural gas (bio-LNG). Bio-CNG and bio-LNG is commonly used as an alternative to diesel fuel for heavy-duty vehicle fleets. Growth in California’s RNG industry coincided with a 2014 final rule by the U.S. Environmental Protection Agency that allows RNG to register and qualify for cellulosic biofuel credits as part of the Renewable Fuel Standard.
Lifecycle greenhouse gas (GHG) emissions associated with RNG producer pathways are typically lower than comparable fossil fuel pathways. Low carbon intensity (CI) fuels below the LCFS annual threshold generate credits, which can then be sold to regulated parties (refiners, importers, and marketers of petroleum products) who need to offset deficits generated by fossil fuels or other fuels with CI scores above the annual threshold. RNG accounted for about 7% of LCFS credits during the first three quarters of 2018.
Throughout most of the program’s history, LCFS credits traded below $100 per metric ton of carbon dioxide equivalent (mtCO2e). Increasing LCFS credit prices, averaging over $150/mtCO2e through the first three quarters of 2018, indicate regulated parties are having greater difficulty in meeting annual carbon intensity targets. Higher LCFS prices have generally caused low CI fuels to enter the California market and provide an incentive to displace fossil fuels. Credit prices are capped at an inflation-adjusted $200/mtCO2e level.
Recent developments suggest RNG will continue to play an important role in California’s effort to decarbonize its economy. SoCalGas, which serves roughly 21 million customers across Central and Southern California, announced a goal to replace 5% of its total natural gas supply with RNG by 2022 and increase that amount to 20% by 2030.
An increasing amount of RNG is being produced in California. In February 2019, Calgren recently began to inject RNG into SoCalGas pipelines from a dairy cluster in Tulare County, CA that captures methane produced by the manure of more than 75,000 cows. The facility is estimated to produce over 2 billion cubic feet (Bcf) of natural gas per year, and additional dairies are expected to join the cluster to potentially create the largest facility of its kind in the United States. Additionally, CR&R Environmental’s anaerobic digester facility in Perris, California, a city approximately 70 miles east of Los Angeles, recently started to inject RNG into SoCalGas pipelines in 2018. Biomethane is produced from green waste that is collected from municipalities surrounding the Los Angeles metropolitan area.
Overview:
(For the week ending Wednesday, March 27, 2019)
- Natural gas spot prices fell at most locations this report week (Wednesday, March 20 to Wednesday, March 27). Henry Hub spot prices fell from $2.83 per million British thermal units (MMBtu) last Wednesday to $2.66/MMBtu yesterday.
- At the Nymex, the April 2019 contract expired yesterday at $2.713/MMBtu, down 11¢/MMBtu from last Wednesday. The May 2019 contract decreased to $2.719/MMBtu, down 11¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging May 2019 through April 2020 futures contracts declined 7¢/MMBtu to $2.881/MMBtu.
- Net withdrawals from working gas totaled 36 Bcf for the week ending March 22. Working natural gas stocks are 1,107 Bcf, which is 20% lower than the year-ago level and 33% lower than the five-year (2014–18) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 64¢/MMBtu, averaging $6.00/MMBtu for the week ending March 27. The price of ethane, propane, butane, and isobutane fell by 12%, 6%, 5%, and 5%, respectively. The price of natural gasoline rose by 2%.
- According to Baker Hughes, for the week ending Tuesday, March 19, the natural gas rig count decreased by 1 to 192. The number of oil-directed rigs fell by 9 to 824. The total rig count decreased by 10, and it now stands at 1,016.
Prices/Supply/Demand:
Prices fall across the country with decreased demand. This report week (Wednesday, March 20 to Wednesday, March 27), Henry Hub spot prices fell 17¢ from $2.83/MMBtu last Wednesday to a weekly low of $2.66/MMBtu yesterday as a result of temperatures that were close to normal for this time of year. At the Chicago Citygate, prices decreased 17¢ from $2.69/MMBtu last Wednesday to $2.52/MMBtu yesterday. Prices at PG&E Citygate in Northern California fell 14¢, down from the weekly high of $3.77/MMBtu last Wednesday to $3.63/MMBtu yesterday. Prices at SoCal Citygate decreased 11¢ from $4.20/MMBtu last Wednesday to the weekly low of $4.09/MMBtu yesterday.
Northeast prices decrease. At the Algonquin Citygate, which serves Boston-area consumers, prices decreased 23¢ from $2.96/MMBtu last Wednesday to $2.73/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices decreased 25¢ from $2.75/MMBtu last Wednesday to the weekly low of $2.50/MMBtu yesterday. Tennessee Zone 4 Marcellus spot prices decreased 24¢ from $2.60/MMBtu last Wednesday to $2.36/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania fell 19¢ from $2.60/MMBtu last Wednesday to $2.41/MMBtu yesterday.
Waha Hub sees negative prices with three force majeures reducing westbound flows. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $0.26/MMBtu last Wednesday, $2.57/MMBtu lower than Henry Hub prices. Prices traded in the negative range for four of the six report days according to data from Natural Gas Intelligence. Yesterday, prices at the Waha Hub averaged an all-time low of -$0.75/MMBtu, $3.41/MMBtu lower than Henry Hub prices.
The El Paso Natural Gas Company extended its force majeure into this week at its Lordsburg and Florida compressor stations in southwestern New Mexico, which went into effect on March 18. As a result, westbound flows out of the Permian Basin decreased by an estimated 0.2 Bcf/d. Although the Florida compressor station is expected to return to service March 31, the Lordsburg compressor station is not expected to return to service until April 5. In addition to this notice, another force majeure on the El Paso system at the San Juan crossover point near the New Mexico/Colorado border has reduced operational capacity from a base capacity of 0.60 Bcf/d to 0.48 Bcf/d.
The Transwestern Pipeline Company lifted a force majeure at a compressor station near Carlsbad, New Mexico. According to the notice, the total capacity for WT1 Station receipt volumes will increase from 0.5 Bcf/d to approximately 0.6 Bcf/d, effective for the last day of this report week.
Supply rises with production growth. According to data from PointLogic Energy, the average total supply of natural gas rose by 1% compared with the previous report week. Dry natural gas production grew by 1% compared with the previous report week. Average net imports from Canada decreased by 7% from last week.
Demand falls across all sectors. 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. Industrial sector consumption decreased by 2% week over week. In the residential and commercial sectors, consumption declined by 2%. Natural gas exports to Mexico were the same as last week, averaging 4.6 Bcf/d.
U.S. LNG exports decrease week over week. Six LNG vessels (five from Sabine Pass and one from Corpus Christi) with a combined LNG-carrying capacity of 22.3 Bcf departed the United States between March 21 and March 27, according to shipping data compiled by Bloomberg. Data for Cove Point LNG exports were unavailable this report week.
Cameron LNG in Louisiana was approved to introduce hazardous fluids and feed gas to fuel gas systems and commission wet flare systems as part of on-going commissioning activities for Train 1, according to a Federal Energy Regulatory Committee (FERC) filing on Wednesday. Train 1 is expected to enter service in second-quarter 2019.
Last week Kinder Morgan, the developer of Elba Island LNG liquefaction facility in Georgia, announced that the start-up of the first train at the facility has been postponed until late April 2019.
Storage:
Net withdrawals from storage totaled 36 Bcf for the week ending March 22, compared with the five-year (2014–18) average net withdrawals of 41 Bcf and last year's net withdrawals of 66 Bcf during the same week. Working gas stocks totaled 1,107 Bcf, which is 551 Bcf lower than the five-year average and 285 Bcf lower 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 28 Bcf to 49 Bcf, with a median estimate of 37 Bcf.
The average rate of net withdrawals from storage is 3% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 2.4 Bcf/d for the remainder of the withdrawal season, total inventories would be 1,085 Bcf on March 31, which is 551 Bcf lower than the five-year average of 1,636 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:
| Spot Prices ($/MMBtu) | Thu, 21-Mar |
Fri, 22-Mar |
Mon, 25-Mar |
Tue, 26-Mar |
Wed, 27-Mar |
|---|---|---|---|---|---|
| Henry Hub |
2.79 |
2.75 |
2.72 |
2.74 |
2.66 |
| New York |
2.76 |
2.72 |
2.75 |
2.68 |
2.50 |
| Chicago |
2.67 |
2.64 |
2.65 |
2.60 |
2.52 |
| Cal. Comp. Avg.* |
2.98 |
2.77 |
2.92 |
2.99 |
2.83 |
| Futures ($/MMBtu) | |||||
| April contract | 2.821 |
2.753 |
2.755 |
2.740 |
2.713 |
| May contract |
2.827 |
2.767 |
2.774 |
2.751 |
2.719 |
| *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: (3/21/19 - 3/27/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| Marketed production | 100.0 |
98.6 |
88.9 |
| Dry production | 89.3 |
88.2 |
79.4 |
| Net Canada imports | 4.7 |
5.1 |
6.8 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.2 |
| Total supply | 94.2 |
93.4 |
86.5 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| U.S. natural gas consumption - Gas Week: (3/21/19 - 3/27/19) | |||
|---|---|---|---|
Average daily values (Bcf/d): |
|||
this week |
last week |
last year |
|
| U.S. consumption | 72.7 |
74.7 |
79.3 |
| Power | 21.5 |
22.4 |
23.8 |
| Industrial | 21.6 |
22.0 |
22.0 |
| Residential/commercial | 29.6 |
30.2 |
33.5 |
| Mexico exports | 4.6 |
4.6 |
4.4 |
| Pipeline fuel use/losses | 6.3 |
6.3 |
5.9 |
| LNG pipeline receipts | 4.1 |
5.5 |
3.2 |
| Total demand | 87.7 |
91.2 |
92.8 |
|
Source: OPIS PointLogic Energy, an IHS Company | |||
| Rigs | |||
|---|---|---|---|
Tue, March 19, 2019 |
Change from |
||
last week |
last year |
||
| Oil rigs | 824 |
-1.1% |
2.5% |
| Natural gas rigs | 192 |
-0.5% |
1.1% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, March 19, 2019 |
Change from |
||
last week |
last year |
||
| Vertical | 53 |
-1.9% |
-15.9% |
| Horizontal | 900 |
-0.8% |
3.4% |
| Directional | 63 |
-3.1% |
1.6% |
| Source: Baker Hughes Inc. | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2019-03-22 |
2019-03-15 |
change |
|
| East | 225 |
245 |
-20 |
|
| Midwest | 248 |
268 |
-20 |
|
| Mountain | 62 |
62 |
0 |
|
| Pacific | 104 |
96 |
8 |
|
| South Central | 467 |
471 |
-4 |
|
| Total | 1,107 |
1,143 |
-36 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (3/22/18) |
5-year average (2014-2018) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 246 |
-8.5 |
287 |
-21.6 |
|
| Midwest | 288 |
-13.9 |
354 |
-29.9 |
|
| Mountain | 88 |
-29.5 |
115 |
-46.1 |
|
| Pacific | 166 |
-37.3 |
201 |
-48.3 |
|
| South Central | 603 |
-22.6 |
700 |
-33.3 |
|
| Total | 1,392 |
-20.5 |
1,658 |
-33.2 |
|
| Source: Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Mar 21) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDD deviation from: |
CDD deviation from: |
|||||||
| Region | HDD Current |
normal |
last year |
CDD Current |
normal |
last year |
||
| New England | 189 |
-7 |
-27 |
0 |
0 |
0 |
||
| Middle Atlantic | 174 |
-7 |
-42 |
0 |
0 |
0 |
||
| E N Central | 197 |
6 |
6 |
0 |
0 |
0 |
||
| W N Central | 190 |
2 |
4 |
0 |
-1 |
0 |
||
| South Atlantic | 115 |
10 |
-4 |
10 |
-2 |
0 |
||
| E S Central | 123 |
23 |
26 |
0 |
-5 |
0 |
||
| W S Central | 78 |
19 |
38 |
1 |
-11 |
-15 |
||
| Mountain | 160 |
6 |
-10 |
2 |
0 |
2 |
||
| Pacific | 72 |
-17 |
-48 |
0 |
-1 |
0 |
||
| United States | 145 |
2 |
-10 |
2 |
-3 |
-2 |
||
|
Note: HDD = heating degree day; CDD = cooling degree day Source: National Oceanic and Atmospheric Administration | ||||||||
Average temperature (°F)
7-day mean ending Mar 21, 2019
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Mar 21, 2019
Source: National Oceanic and Atmospheric Administration
