In the News:
Average well productivity has increased in the Haynesville formation
The initial production rate of natural gas from a new well drilled in the Haynesville formation of north Louisiana and eastern Texas increased from about 8.1 million cubic feet per day (MMcf/d) in 2014 to approximately 17.3 MMcf/d in 2020, based on an assessment of well-level data from Enverus. Average initial production rates (usually the first full 30 days of production) increased 66% in wells drilled between 2014 and 2016, 19% from 2016 to 2018, and 8% from 2018 to 2020. During this same period, the average length of the horizontal portion of a Haynesville wellbore, typically referred to as its lateral length, was also increasing but at a slower pace. The Haynesville formation is the second-largest shale-sourced natural gas-producing formation in the United States, and its current total gross withdrawals are near record highs.
By design, a horizontal well produces from an interval of natural gas-bearing rock as wide as the lateral section of the wellbore is long. With increased lateral length within a given wellbore, the amount of natural gas-bearing rock accessed by the wellbore increases in direct proportion to this additional lateral length. Growth in average lateral length of Haynesville formation wells increased 8% between 2014 and 2016, then increased an additional 5% from 2016 to 2018, and 3% from 2018 to 2020.
By adjusting, or normalizing, for these longer lateral lengths, we can assess increased well productivity from improved completion designs. Improved completion designs can include different proppant (sand or similar material) sizes and types, larger or varied water and gel mixes to carry the proppant throughout the induced fractures, and improved hydraulic fracturing techniques allowing for better fracture propagation. Based on the normalized well productivity data, we calculate that the production rate from the average Haynesville natural gas well increased by approximately 54% from 2014 to 2016. However, this rate of increase dropped significantly in the following years to 13% from 2016 to 2018 and to 5% from 2018 to 2020.
This article is the second in a series of articles on regional natural gas productivity. The first article, dated January 27, 2022, addressed similar trends in the Marcellus formation.
Overview:
(For the week ending Wednesday, April 27, 2022)
- Spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, April 20 to Wednesday, April 27). The Henry Hub spot price fell from $7.04 per million British thermal units (MMBtu) last Wednesday to $6.94/MMBtu yesterday.
- International spot prices: International natural gas spot prices were mixed this report week. Bloomberg Finance, L.P. reports that the swap prices for liquefied natural gas (LNG) cargoes in East Asia fell $4.43/MMBtu to a weekly average of $25.39/MMBtu. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead prices increased 50 cents to a weekly average of $30.94/MMBtu. The price at TTF averaged above the East Asia price for the second week in a row. Historically, the natural gas prices in East Asia average above natural gas prices in Europe. In the same week last year (week ending April 28, 2021), the prices in East Asia and at the TTF were $8.58/MMBtu and $7.48/MMBtu, respectively.
- Futures: The May 2022 NYMEX contract expired yesterday at $7.267/MMBtu, up 33 cents from last Wednesday. The June 2022 NYMEX contract price increased to $7.339/MMBtu, up 27 cents from last Wednesday to yesterday. The price of the 12-month strip averaging June 2022 through May 2023 futures contracts climbed 16 cents to $6.839/MMBtu.
- Storage: The net injections to working gas totaled 40 billion cubic feet (Bcf) for the week ending April 22. Working natural gas stocks totaled 1,490 Bcf, which is 21% 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, fell by 51 cents/MMBtu, averaging $12.22/MMBtu for the week ending April 27. The ethane price at Month Belvieu fell by 3%, following the 5% decrease in natural gas prices at the Houston Ship Channel. The ethane premium to natural gas widened by 10%. The price of ethylene also fell by 3%, leaving the ethylene premium over ethane relatively unchanged week over week. Brent crude oil prices fell 4%, pulling down the prices of propane, butanes, and natural gasoline. The price of propane fell 5%, while the propane discount to crude oil remained relatively unchanged. The prices of normal butane and isobutane fell 3% and 1%, respectively. The price of natural gasoline fell 6%.
- Rigs: According to Baker Hughes, for the week ending Tuesday, April 19, the natural gas rig count was up by 1 rig from a week ago to 144 rigs. The Eagle Ford added one rig. The number of oil-directed rigs increased by 1 to 549 rigs. The Ardmore Woodford and Cana Woodford each added one rig, the Williston added two rigs, and three rigs were dropped in unspecified production regions. The total rig count now stands at 695, the highest level since March 27, 2020, and 257 rigs more than the same week last year.
Prices/Supply/Demand:
Most prices along the Gulf Coast rise as a result of forecasts of higher temperatures and rising air conditioning demand. This report week (Wednesday, April 20 to Wednesday, April 27), the Henry Hub spot price fell 10 cents from $7.04 per million British thermal units (MMBtu) last Wednesday to $6.94/MMBtu yesterday. The Henry Hub spot price fell to a weekly low of $6.40/MMBtu on Monday. Outside of the Henry Hub, prices along the Gulf Coast and across the Southeast were all higher this report week. Higher temperatures across the region resulted in rising air conditioning demand, leading to a 0.3 Bcf/d (2%) increase in natural gas consumption for power generation. This increase was offset by lower consumption in the residential and commercial sectors, which decreased 0.4 Bcf/d (20%), according to data from PointLogic. Temperatures in the Houston Area averaged 75°F this report week, 3°F higher than normal. On Thursday, temperatures in Houston averaged 80°F, which was 8°F higher than normal, and they remained higher than normal until Tuesday. NOAA forecasts above-normal temperatures to continue throughout the region this weekend through early May. Production from the Federal Offshore Gulf of Mexico decreased 0.2 Bcf/d (12%) this report week. Feedgas deliveries to liquefied natural gas (LNG) export terminals along the Gulf Coast remained flat at 11.0 billion cubic feet per day (Bcf/d) this report week. Pipeline natural gas deliveries to terminals in South Louisiana decreased by 60 million cubic feet per day (MMcf/d) (1%) to 7.6 Bcf/d, and natural gas deliveries to terminals in South Texas increased by 70 MMcf/d (2%), according to data from PointLogic.
Prices in the Midwest increase as temperatures shift from above-normal to below-normal during the report week. At the Chicago Citygate, the price rose 30 cents from $6.71/MMBtu last Wednesday to $7.01/MMBtu yesterday. The Chicago Citygate price fell to a weekly low of $6.32/MMBtu on Friday. Temperatures in the Chicago Area averaged a normal 52°F this report week, though temperatures were well above normal on several days. On Saturday, temperatures in Chicago reached a high of 84°F, leading to 13 fewer heating degree days (HDD) than normal and 3 cooling degree days (CDD) more than normal. As a result, natural gas consumption by the residential and commercial sectors in the Midwest decreased by 2.9 Bcf/d (40%) and flows of natural gas to the region declined. Yesterday, temperatures in the Chicago Area averaged 37°F, which was 17°F below normal. NOAA forecasts temperatures to remain below normal through the weekend and into early May.
Prices rise across much of the West as mid-continent production falls. The price at PG&E Citygate in Northern California rose 18 cents, up from $7.79/MMBtu last Wednesday to $7.97/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, increased 7 cents, up from $6.86/MMBtu last Wednesday to $6.93/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 California market through the Ruby Pipeline, rose 7 cents, up from $6.83/MMBtu last Wednesday to $6.90/MMBtu yesterday. The price at Sumas on the Canada-Washington border, the main pricing point for the Pacific Northwest, rose 11 cents, up from $6.72/MMBtu last Wednesday to $6.83/MMBtu yesterday. Temperatures in the Seattle City Area averaged 51°F this report week, 4°F higher than last report week and 1°F below normal. Natural gas consumption by all sectors in the Pacific Northwest fell 0.5 Bcf/d (22%), according to data from PointLogic. Production across the Plains decreased by 0.4 Bcf/d (27%) this report week, as a result of below-normal temperatures that caused production disruptions in North Dakota, though volumes are beginning to be restored.
The price at SoCal Citygate in Southern California decreased 31 cents, from $7.60/MMBtu last Wednesday to $7.29/MMBtu yesterday. Temperatures in the Riverside Area averaged 66°F this report week, 2°F higher than normal. Natural gas consumption by the power generation sector in California increased by 0.1 Bcf/d (8%), according to data from PointLogic.
Prices in New England increase as lower-than-normal temperatures linger in the region and pipelines experience outages and maintenance. At the Algonquin Citygate, which serves Boston-area consumers, the price went up $3.53 from $6.67/MMBtu last Wednesday to $10.20/MMBtu yesterday. Weather forecasts include an upper-level low pressure system over the Gulf of Maine producing unsettled weather over northern New England through Friday, including snow in Northern Maine. Below-normal temperatures for this time in April in New England and an anticipated increase in demand for heating followed pipeline outages and maintenance this week. According to Algonquin Gas Transmission (AGT), the J system, which delivers natural gas in the Boston area, was under a force majeure (Notice ID 120006) from April 24 through April 27. AGT has completed the repairs and lifted the force majeure. Tennessee Gas Pipeline began maintenance on April 24 at Compressor Station 245 in Herkimer County, New York, which limited flows by approximately 200 MMcf/d to the Boston area earlier this week. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 23 cents from $6.45/MMBtu last Wednesday to $6.68/MMBtu yesterday.
Prices in the Appalachia production region increase week over week. The Tennessee Zone 4 Marcellus spot price increased 19 cents from $6.24/MMBtu last Wednesday to $6.43/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 22 cents from $6.21/MMBtu last Wednesday to $6.43/MMBtu yesterday. Natural gas production increased week over week by 0.2 Bcf/d (1%) to 33.9 Bcf/d. Net natural gas flows out of the region decreased by an average 0.2 Bcf/d (1%) to 24.7 Bcf/d. Rover Pipeline announced preventative maintenance this week, which the company cautioned may limit westbound natural gas flows on the mainline in Ohio.
Prices in the Permian production region rise, narrowing the discount to Henry Hub. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 17 cents this report week, from $6.32/MMBtu last Wednesday to $6.49/MMBtu yesterday. The Waha Hub traded 45 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 72 cents below the Henry Hub price. Total demand in West Texas increased by an average 0.2 Bcf/d (2%) to 11.0 Bcf/d, which was led by an increase of 0.2 Bcf/d (10%) in net natural gas flows to Mexico out of the region.
U.S. natural gas supply decreases slightly this week. The average total supply of natural gas fell by 0.5% (0.5 Bcf/d) this week when compared with the previous report week, according to data from PointLogic. Dry natural gas production decreased by 0.5% (0.5 Bcf/d) and average net imports from Canada were flat compared with last week.
U.S. consumption of natural gas decreases in all sectors this week. Total U.S. consumption of natural gas fell by 9.6% (7.0 Bcf/d) compared with the previous report week, as consumption across all sectors decreased, according to data from PointLogic. Consumption in the residential and commercial sectors fell more than in the power and industrial sectors combined, declining 27.6% (6.2 Bcf/d), with above-average daytime temperatures across the Central and Eastern United States. Natural gas consumed for power generation declined slightly by 0.5% (0.1 Bcf/d) and the industrial sector decreased by 2.8% (0.6 Bcf/d) week over week. Total natural gas exports to Mexico decreased 2.3% (0.1 Bcf/d) and natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.2 Bcf/d, same as last week.
U.S. LNG exports decrease by three vessels this week from last week. Twenty-three LNG vessels (nine from Sabine Pass, five from Freeport, four from Corpus Christi, three from Cameron, and one each from Cove Point and Calcasieu Pass) with a combined LNG-carrying capacity of 84 Bcf departed the United States between April 21 and April 27, according to shipping data provided by Bloomberg Finance, L.P.
Storage:
The net injections into storage totaled 40 Bcf for the week ending April 22, compared with the five-year (2017–2021) average net injections of 53 Bcf and last year's net injections of 18 Bcf during the same week. Working natural gas stocks totaled 1,490 Bcf, which is 305 Bcf lower than the five-year average and 406 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 20 Bcf to 47 Bcf, with a median estimate of 40 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, 21-Apr |
Fri, 22-Apr |
Mon, 25-Apr |
Tue, 26-Apr |
Wed, 27-Apr |
|---|---|---|---|---|---|
| Henry Hub |
6.88 |
6.55 |
6.40 |
6.82 |
6.94 |
| New York |
6.19 |
5.71 |
5.87 |
6.79 |
6.68 |
| Chicago |
6.59 |
6.32 |
6.63 |
6.90 |
7.01 |
| Cal. Comp. Avg.* |
7.12 |
6.65 |
6.89 |
7.30 |
7.34 |
| Futures ($/MMBtu) | |||||
| May contract | 6.957 |
6.534 |
6.669 |
6.850 |
7.267 |
| June contract |
7.096 |
6.663 |
6.805 |
6.978 |
7.339 |
|
Sources: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. |
|||||
| U.S. natural gas supply - Gas Week: (4/21/22 - 4/27/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 105.7 |
106.5 |
104.5 |
| Dry production | 93.9 |
94.4 |
92.3 |
| Net Canada imports | 6.0 |
6.0 |
4.9 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 100.0 |
100.5 |
97.3 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| U.S. natural gas consumption - Gas Week: (4/21/22 - 4/27/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 65.3 |
72.2 |
70.0 |
| Power | 26.6 |
26.7 |
25.3 |
| Industrial | 22.5 |
23.1 |
22.6 |
| Residential/commercial | 16.2 |
22.4 |
22.1 |
| Mexico exports | 6.1 |
6.3 |
6.0 |
| Pipeline fuel use/losses | 6.3 |
6.5 |
6.4 |
| LNG pipeline receipts | 12.2 |
12.2 |
11.6 |
| Total demand | 89.9 |
97.2 |
93.9 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, April 19, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 549 |
0.2% |
60.1% |
| Natural gas rigs | 144 |
0.7% |
53.2% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, April 19, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 25 |
0.0% |
13.6% |
| Horizontal | 639 |
0.5% |
61.0% |
| Directional | 31 |
-3.1% |
63.2% |
| 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 | 2022-04-22 |
2022-04-15 |
change |
|
| East | 238 |
238 |
0 |
|
| Midwest | 309 |
304 |
5 |
|
| Mountain | 90 |
89 |
1 |
|
| Pacific | 171 |
169 |
2 |
|
| South Central | 681 |
650 |
31 |
|
| Total | 1,490 |
1,450 |
40 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (4/22/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 320 |
-25.6 |
301 |
-20.9 |
|
| Midwest | 426 |
-27.5 |
385 |
-19.7 |
|
| Mountain | 119 |
-24.4 |
105 |
-14.3 |
|
| Pacific | 216 |
-20.8 |
197 |
-13.2 |
|
| South Central | 815 |
-16.4 |
808 |
-15.7 |
|
| Total | 1,896 |
-21.4 |
1,795 |
-17.0 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Apr 21) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 122 |
-5 |
-1 |
0 |
0 |
0 |
||
| Middle Atlantic | 127 |
18 |
20 |
0 |
0 |
0 |
||
| E N Central | 154 |
41 |
9 |
0 |
0 |
0 |
||
| W N Central | 167 |
65 |
10 |
0 |
-1 |
0 |
||
| South Atlantic | 69 |
18 |
12 |
21 |
5 |
0 |
||
| E S Central | 65 |
18 |
-12 |
2 |
-3 |
2 |
||
| W S Central | 19 |
-1 |
-40 |
42 |
19 |
35 |
||
| Mountain | 96 |
-11 |
-47 |
11 |
2 |
7 |
||
| Pacific | 76 |
14 |
27 |
0 |
-3 |
0 |
||
| United States | 106 |
22 |
4 |
9 |
2 |
5 |
||
|
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 21, 2022
Source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Apr 21, 2022
Source: National Oceanic and Atmospheric Administration
