In the News:
Gas-oil ratio continues to rise in the Bakken region
Gross natural gas withdrawals in North Dakota’s Bakken region increased more quickly than crude oil production in 2021. Natural gas withdrawals outpaced crude oil production in the region because of the continually rising ratio of well-level natural gas production to crude oil production, known as the gas-oil ratio (GOR). In response to both the rising GOR and state regulations, producers in the region are capturing more natural gas and sending it to natural gas processing plants rather than flaring it at the wellhead.
The GOR in the Bakken region has been gradually increasing since 2008 and has increased at a faster rate in recent years. The GOR can range from near zero (little or no associated natural gas produced with oil) to infinity (no hydrocarbon liquids or crude oil of any kind produced with natural gas). The ratio is an indicator of the amount of natural gas that is released with the oil at the start of production from a reservoir. As wells mature, the GOR typically increases as a result of oil and natural gas production and the accompanying decline in reservoir pressure.
Gross natural gas withdrawals in the Bakken fell by 8% in 2020 due to demand decline and production shut ins as a result of the economic effects of the COVID-19 pandemic. In 2021, gross natural gas withdrawals rose by 9%, reaching a new average annual high of 2.97 billion cubic feet per day (Bcf/d), slightly surpassing the previous high of 2.95 Bcf/d set in 2019. Although gross natural gas withdrawals have been rising, the Bakken’s average annual crude oil production peaked at 1.45 million barrels per day in 2019 before falling by 17% in 2020 and by 6% in 2021.
North Dakota’s regulators and operators have undertaken several steps to reduce natural gas flaring at the wellhead that has accompanied the higher natural gas production. The North Dakota Industrial Commission (NDIC) raised natural gas capture targets in the state from 74% in October 2014 to 91% in the beginning of November 2020. The natural gas capture target is the amount of natural gas captured at the wellhead rather than flared. As of December 2021, North Dakota’s natural gas flaring rate averaged 7.5%, which means that 92.5% of the natural gas was captured.
To meet the capture targets, midstream companies operating in North Dakota expanded natural gas processing plant capacity. The NDIC reports that natural gas processing capacity in the state increased from 1.0 Bcf/d in 2013 to 4.0 Bcf/d in 2021, and the NDIC expects it to increase to 4.2 Bcf/d in 2023.
In February 2022, WBI Energy placed into service the 100-mile North Bakken Expansion pipeline, which has the capacity to transport 250 million cubic feet per day of natural gas from production centers in Tioga, North Dakota, to demand centers in McKenzie County, North Dakota. The new pipeline will further reduce natural gas flaring in the Bakken, according to WBI Energy.
Overview:
(For the week ending Wednesday, April 20, 2022)
- Spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, April 13 to Wednesday, April 20). The Henry Hub spot price rose from $6.70 per million British thermal units (MMBtu) last Wednesday to $7.04/MMBtu yesterday.
- International spot prices: International natural gas spot prices declined this report week. Bloomberg Finance, L.P. reports that the swap prices for liquefied natural gas (LNG) cargoes in East Asia fell $3.39/MMBtu to a weekly average of $29.83/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead prices fell $2.39 to a weekly average of $30.45/MMBtu. The price at TTF averaged above the East Asia price this week, after dropping below East Asia last week. Historically, the natural gas prices in East Asia average above natural gas prices in Europe. In the same week last year (week ending April 21, 2021), the prices in East Asia and at the TTF were $7.75/MMBtu and $7.49/MMBtu, respectively.
- Futures: The price of the May 2022 NYMEX contract decreased 6 cents, from $6.997/MMBtu last Wednesday to $6.937/MMBtu yesterday. The May 2022 contract reached $7.82/MMBtu on Monday—the highest close-of-day price for a near-month futures contract since September 2008—before declining on Tuesday and Wednesday. The price of the 12-month strip averaging May 2022 through April 2023 futures contracts declined 7.1 cents to $6.887/MMBtu.
- Storage: The net injections to working gas totaled 53 billion cubic feet (Bcf) for the week ending April 15. Working natural gas stocks totaled 1,450 Bcf, which is 23% lower than the year-ago level and 17% lower than the five-year (2017–2021) average for this week.
- NGPLs: The natural gas plant liquids (NGPLs) composite price at Mont Belvieu, Texas, rose by 52 cents/MMBtu, averaging $12.73/MMBtu for the week ending April 20. Natural gas prices at the Houston Ship Channel increased by 10%, while the ethane price at Month Belvieu rose 6%. The ethane premium to natural gas narrowed by 14%. The ethylene premium over ethane remained relatively unchanged week over week. Prices of propane, isobutane, and natural gasoline each rose 4%, following the price of Brent crude oil, which rose 5%. The price of normal butane remained relatively unchanged compared with last week. The propane discount to crude oil widened by 11%.
- Rigs: According to Baker Hughes, for the week ending Tuesday, April 12, the natural gas rig count was up by 2 rigs from a week ago to 143 rigs. The Barnett and the Haynesville each added one rig. The number of oil-directed rigs increased by 2 to 548 rigs. The Cana Woodford added one rig, the Eagle Ford added three rigs, and the Permian added two rigs. One rig was dropped in the Haynesville and three rigs were dropped in unspecified production regions. The total rig count now stands at 693, the highest level since March 27, 2020, and 254 rigs more than the same week last year.
Prices/Supply/Demand:
Prices along the Gulf Coast rise with the national average. This report week (Wednesday, April 13 to Wednesday, April 20), the Henry Hub spot price rose 34 cents from $6.70 per million British thermal units (MMBtu) last Wednesday to $7.04/MMBtu yesterday. On Monday, the Henry Hub spot price averaged $7.56/MMBtu, the highest average price since February, 17, 2021. Prices along the Gulf Coast and across the Southeast were all higher this report week, despite total consumption of natural gas in the region falling by 0.4 Bcf/d (2%). Temperatures in the Houston Area averaged 73°F this report week, 3°F higher than normal. Feedgas deliveries to liquefied natural gas (LNG) export terminals along the Gulf Coast decreased by 0.2 Bcf/d (2%) to 11.0 Bcf/d this report week. Feedgas deliveries to terminals in South Louisiana increased by 0.2 Bcf/d (2%) and deliveries to terminals in South Texas decreased by 0.4 Bcf/d (10%), according to data from PointLogic. Venture Global’s Calcasieu Pass received approval on April 20 from the Federal Energy Regulatory Commission (FERC) to introduce hazardous fluids into liquefaction Block 6, another step in the ongoing commissioning of the terminal.
Prices in the Midwest fluctuate during the week. At the Chicago Citygate, the price increased 1 cent from $6.70/MMBtu last Wednesday to $6.71/MMBtu yesterday, after reaching a weekly high of $7.65/MMBtu on Monday. Temperatures in the Chicago area averaged 36°F on Sunday, April 17, leading to 14 more heating degree days (HDD) than normal, as cooler weather moved into the Midwest on Sunday. Temperatures have increased slightly since Sunday but have remained below normal, averaging 47°F yesterday and leading to 4 HDDs more than normal for the day. Natural gas consumption by the residential and commercial sectors in the Midwest increased 1.6 Bcf/d (29%) this report week, according to data from PointLogic.
Prices in the West rise with mixed weather along the coast. The price at PG&E Citygate in Northern California rose 12 cents, up from $7.67/MMBtu last Wednesday to $7.79/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, increased 19 cents, up from $6.67/MMBtu last Wednesday to $6.86/MMBtu yesterday. The price at Opal in Southwest Wyoming (the main trading point for natural gas in the Rocky Mountain region and the origin point for deliveries into the Northern California market through the Ruby Pipeline) rose 32 cents, up from $6.51/MMBtu last Wednesday to $6.83/MMBtu yesterday. The price at Sumas on the Canada-Washington border, the main pricing point for the Pacific Northwest, rose 17 cents, up from $6.55/MMBtu last Wednesday to $6.72/MMBtu yesterday. Temperatures in the Seattle City area averaged 47°F, unchanged from last report week, but 4°F lower than normal. The price at SoCal Citygate in Southern California increased 69 cents, up from $6.91/MMBtu last Wednesday to $7.60/MMBtu yesterday. Temperatures in the Riverside area, inland from Los Angeles, averaged 64°F this report week, 1°F higher than normal. In an update to its original force majeure notice on August 15, 2021, El Paso Natural Gas Company (EPNG) gave notice on April 19 that Line 2000 remains effectively removed from service from the Black River compressor station in West Texas to the California border with no timeframe for bringing it back to full service. EPNG expects the line to continue to be out of service for several months.
Prices in the Northeast rise as a late season winter storm and colder-than-normal temperatures result in increased demand. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 41 cents from $6.26/MMBtu last Wednesday to $6.67/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 (Transco Zone 6) trading point for New York City, the price increased 24 cents from $6.21/MMBtu last Wednesday to $6.45/MMBtu yesterday. Prices in the Northeast were volatile throughout the week and ended the week higher than at the start of the week. Algonquin City Gate and Transco Zone 6 reached highs on Monday of $7.79/MMBtu and $7.58/MMBtu, respectively. Temperatures were just as volatile. In the New York City area, temperatures ranged from an average 68°F at the start of the report week to an average 45°F on Tuesday, April 19. The mid-April storm resulted in unseasonal accumulations of snow throughout the Northeast, and power outages affecting up to 300,000 customers in the region, and nearly 200,000 of these customers were in New York State. Natural gas consumption in the Northeast increased by an average 1.0 Bcf/d (6%) to 17.2 Bcf/d, led by an average increase in consumption in the residential and commercial sectors of 0.6 Bcf/d (9%) to 7.5 Bcf/d, according to data from PointLogic.
Prices in the Appalachia production region increase as colder-than-normal temperatures move through the area, increasing consumption. The Tennessee Zone 4 Marcellus spot price increased 28 cents from $5.96/MMBtu last Wednesday to $6.24/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 12 cents from $6.09/MMBtu last Wednesday to $6.21/MMBtu yesterday. Natural gas production increased week over week by an average 0.3 Bcf/d (1%) to 33.6 Bcf/d, according to data from PointLogic. Colder-than-normal temperatures in the Pittsburgh area resulted in an average of 19 HDDs, which is 6 more than normal. Natural gas consumption rose on average by 0.7 Bcf/d (10%) to 7.9 Bcf/d, led by an increase in consumption in the residential and commercial sectors of an average 0.4 Bcf/d (15%) to 3.0 Bcf/d, according to data from PointLogic. Net natural gas flows out of the region declined by an average of 0.2 Bcf/d (1%) to 24.8 Bcf/d. Natural gas flows to the Atlantic and New York and New Jersey areas decreased by an average 0.3 Bcf/d (5%) and 0.2 Bcf/d (3%), respectively, offsetting an increase in gas flows to the Midwest of an average 0.3 Bcf/d (4%) to 6.1 Bcf/d.
The price discount in the Permian production region relative to Henry Hub increases and production holds steady in the region. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 25 cents this report week, from $6.07/MMBtu last Wednesday to $6.32/MMBtu yesterday. The Waha Hub traded 72 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 63 cents below the Henry Hub price. Average production from the New Mexico side of the Permian Basin decreased week over week by 0.3 Bcf/d (5%) to 5.0 Bcf/d. Production from other areas in the basin increased by approximately the same amount, which resulted in total production being relatively unchanged from a week ago, averaging 14.6 Bcf/d, according to data from PointLogic.
U.S. supply of natural gas remains unchanged this week. The average total supply of natural gas was unchanged compared with last week, averaging 100.5 Bcf/d, according to data from PointLogic. Dry natural gas production decreased by 0.4% (0.4 Bcf/d) compared with the previous report week, and average net imports from Canada increased by the same amount, 0.4 Bcf/d, which was a 6.5% increase.
U.S. total consumption of natural gas increases this week. Total U.S. consumption of natural gas rose by 3.0% (2.1 Bcf/d) compared with the previous report week, according to data from PointLogic. The residential and commercial sectors had the largest gain from the previous report week, increasing by 7.6% (1.6 Bcf/d) as lower-than-normal temperatures affected most of the continental United States, according to NOAA. Natural gas consumed for power generation climbed by 1.4% (0.4 Bcf/d) week over week, and industrial sector consumption increased by 0.8% (0.2 Bcf/d). Natural gas exports to Mexico increased 6.9% (0.4 Bcf/d) and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.2 Bcf/d, or 0.2 Bcf/d lower than last week.
U.S. LNG exports increase by six vessels this week from last week. Twenty-six LNG vessels (10 from Sabine Pass, 5 from Corpus Christi, 4 from Cameron, 3 from Freeport, 2 from Cove Point, and 1 each from Calcasieu Pass and Elba Island) with a combined LNG-carrying capacity of 97 Bcf departed the United States between April 14 and April 20, according to shipping data provided by Bloomberg Finance, L.P. This report week had the highest number of export cargoes departing the United States since the week of February 3 to February 9, 2022, when 27 were reported.
Storage:
The net injections into storage totaled 53 Bcf for the week ending April 15, compared with the five-year (2017–2021) average net injections of 42 Bcf and last year's net injections of 42 Bcf during the same week. Working natural gas stocks totaled 1,450 Bcf, which is 292 Bcf lower than the five-year average and 428 Bcf lower than last year at this time.
According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net injections of 28 Bcf to 51 Bcf, with a median estimate of 43 Bcf.
More storage data and analysis can be found on the Natural Gas Storage Dashboard and the Weekly Natural Gas Storage Report.
See also:
Source: U.S. Energy Information Administration, Drilling Productivity Report
Note: Each curve represents average gas-oil ratio (GOR) of all wells starting production in a given year.
Source: U.S. Energy Information Administration, Drilling Productivity Report
| Spot Prices ($/MMBtu) | Thu, 14-Apr |
Fri, 15-Apr |
Mon, 18-Apr |
Tue, 19-Apr |
Wed, 20-Apr |
|---|---|---|---|---|---|
| Henry Hub | 6.93 | HOLIDAY | 7.56 | 7.39 | 7.04 |
| New York | 6.80 | HOLIDAY | 7.58 | 6.78 | 6.45 |
| Chicago | 6.94 | HOLIDAY | 7.65 | 6.96 | 6.71 |
| Cal. Comp. Avg.* | 7.21 | HOLIDAY | 7.96 | 7.36 | 7.28 |
| Futures ($/MMBtu) | |||||
| May Contract | 7.300 | HOLIDAY | 7.820 | 7.176 | 6.937 |
| June Contract | 7.423 | HOLIDAY | 7.958 | 7.277 | 7.065 |
| *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: (4/14/22 - 4/20/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 106.5 |
107.0 |
104.1 |
| Dry production | 94.4 |
94.8 |
92.1 |
| Net Canada imports | 6.0 |
5.6 |
4.7 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 100.5 |
100.5 |
96.8 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| U.S. natural gas consumption - Gas Week: (4/14/22 - 4/20/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 72.3 |
70.1 |
68.7 |
| Power | 26.6 |
26.3 |
25.1 |
| Industrial | 23.2 |
23.0 |
22.6 |
| Residential/commercial | 22.5 |
20.9 |
21.0 |
| Mexico exports | 6.2 |
5.8 |
6.5 |
| Pipeline fuel use/losses | 6.5 |
6.5 |
6.4 |
| LNG pipeline receipts | 12.2 |
12.4 |
11.7 |
| Total demand | 97.3 |
94.9 |
93.2 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, April 12, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 548 |
0.4% |
59.3% |
| Natural gas rigs | 143 |
1.4% |
52.1% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, April 12, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 25 |
-3.8% |
19.0% |
| Horizontal | 636 |
0.8% |
59.8% |
| Directional | 32 |
0.0% |
60.0% |
| Source: Chart by the U.S. Energy Information Administration (EIA), based on data from Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2022-04-15 |
2022-04-08 |
change |
|
| East | 238 |
229 |
9 |
|
| Midwest | 304 |
293 |
11 |
|
| Mountain | 89 |
90 |
-1 |
|
| Pacific | 169 |
169 |
0 |
|
| South Central | 650 |
617 |
33 |
|
| Total | 1,450 |
1,397 |
53 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (4/15/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 323 |
-26.3 |
290 |
-17.9 |
|
| Midwest | 420 |
-27.6 |
376 |
-19.1 |
|
| Mountain | 118 |
-24.6 |
102 |
-12.7 |
|
| Pacific | 209 |
-19.1 |
190 |
-11.1 |
|
| South Central | 808 |
-19.6 |
785 |
-17.2 |
|
| Total | 1,878 |
-22.8 |
1,742 |
-16.8 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Apr 14) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 103 |
-40 |
13 |
0 |
0 |
0 |
||
| Middle Atlantic | 91 |
-35 |
17 |
1 |
1 |
1 |
||
| E N Central | 123 |
-7 |
45 |
0 |
0 |
-1 |
||
| W N Central | 135 |
14 |
14 |
0 |
-1 |
0 |
||
| South Atlantic | 60 |
-3 |
31 |
18 |
5 |
-2 |
||
| E S Central | 65 |
7 |
37 |
8 |
3 |
2 |
||
| W S Central | 25 |
-2 |
8 |
34 |
16 |
1 |
||
| Mountain | 140 |
21 |
22 |
7 |
0 |
-3 |
||
| Pacific | 80 |
10 |
16 |
4 |
2 |
4 |
||
| United States | 94 |
-4 |
25 |
9 |
4 |
0 |
||
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from the National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Apr 14, 2022
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal (°F)
7-day mean ending Apr 14, 2022
Source: National Oceanic and Atmospheric Administration
