In the News:
Natural gas-directed rigs in the Appalachian Basin plateaued in the second half of 2021
One response to rising natural gas prices has typically been for producers to increase drilling activity and to employ more drilling rigs. In the second half of 2021, however, the number of natural gas-directed rigs in the Appalachian Basin did not keep pace with the rise in natural gas prices. Changes in the number of operating rigs have historically followed changes in price, with a lag of about four months. Over a period of seven months in 2021, as the U.S. benchmark Henry Hub price more than doubled from a monthly average of $2.62 per million British thermal units (MMBtu) in March to an average $5.51/MMBtu in October, the natural gas-directed rig count in the Appalachian Basin dropped from 39 to 37 rigs. The rig count has risen slightly since then, averaging 40 rigs in December 2021 and 42 rigs in January 2022.
Producers in the Appalachian Basin may have had several possible reasons to not add rigs to their drilling fleets in the fourth quarter of 2021 (beyond the 40 rigs reached in August 2021) amid rising natural gas prices. Pipeline takeaway capacity out of the production area remains constrained under certain conditions, placing an upward limit on the amount of natural gas that can be moved out of the region to consuming areas. The FM100 Project and the Leidy South Project, two of the more recent pipeline expansion projects to be completed in the Appalachian Basin, added a combined 0.91 billion cubic feet per day (Bcf/d) of takeaway capacity when completed in December 2021. Total pipeline takeaway capacity out of the Appalachian Basin currently averages 36 Bcf/d, according to IHS Markit estimates.
In addition, initial well-level production in the Appalachian Basin has nearly doubled in the past four years, from an average of 17 million cubic feet per day (MMcf/d) per month for new wells between 2017 and 2019 to an average of 29 MMcf/d per month in 2021 as a result of increased well productivity. These efficiencies allow producers to maintain production levels without drilling as many new wells. Drawing down the drilled but uncompleted well (DUC) inventory may have also been a factor contributing to sustained production levels without employing additional rigs. According to IHS Markit, production averaged 34.8 Bcf/d in the second half of 2021, which is the highest average for a six-month period since production began in 2008.
Financial reasons were likely another factor leading producers to forgo adding rigs at the end of 2021. Producers who hedged their 2021 production at lower natural gas prices were unable to benefit from higher prices in the second half of 2021. Futures prices at the time also indicated that the high prices might not be sustained, further limiting producers’ financial incentives to increase production. According to publicly available data, two of the top five producers in the Appalachian Basin revised down their guidance on capital spending for 2021, and at least two others held it flat, choosing instead to use higher free cash flow to draw down debt, increase dividends, and improve cash balances.
Overview:
(For the week ending Wednesday, February 2, 2022)
- Natural gas spot prices rose at most locations this report week (Wednesday, January 26 to Wednesday, February 2). The Henry Hub spot price rose from $4.37/MMBtu last Wednesday to $6.44/MMBtu yesterday.
- International natural gas prices were mixed this report week. Bloomberg Finance, L.P. reports that swap prices for liquefied natural gas (LNG) cargos in East Asia for the balance of February rose $3.82 to a weekly average of $26.29/MMBtu from $22.46/MMBtu last week—the lowest weekly average since mid-September 2021. At the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, the day-ahead prices fell $1.08 to a weekly average of $27.64/MMBtu. In the same week last year (week ending February 3, 2021), prices in East Asia and at TTF were $8.65/MMBtu and $6.68/MMBtu, respectively.
- The February 2022 NYMEX contract expired Thursday at $6.265/MMBtu, up $1.988 from last Wednesday. The March 2022 NYMEX contract price increased to $5.501/MMBtu, up $1.224 from last Wednesday to yesterday. The price of the 12-month strip averaging March 2022 through February 2023 futures contracts climbed $1.007 to $5.192/MMBtu.
- The net withdrawals from working gas totaled 268 billion cubic feet (Bcf) for the week ending January 28. Working natural gas stocks totaled 2,323 Bcf, which is 14% lower than the year-ago level and 6% lower than the five-year (2017–2021) average for this week.
- The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by $1.04/MMBtu, averaging $11.70/MMBtu for the week ending February 2. Ethane prices rose 16%, which is less than the 24% increase in natural gas prices at the Houston Ship Channel. The ethane premium to natural gas decreased by 4% for the week ending February 2. Propane prices rose 9% after strong inventory draws related to the colder-than-average weather over the past two weeks. Normal butane and isobutane prices rose 11%, likely due to higher demand for winter-gasoline blending. Natural gasoline prices rose 3%, following the price of Brent crude oil, which also rose 3%.
- According to Baker Hughes, for the week ending Tuesday, January 25, the natural gas rig count increased by 2 to 115 rigs. The Marcellus and the Haynesville each gained one rig. The number of oil-directed rigs increased by 4 to 495 rigs. Two rigs were added in the Barnett, where no rig has been in operation since the first week of December 2021. The total rig count now stands at 610, the highest level since April 3, 2020, and 226 rigs more than last year at this time.
Prices/Supply/Demand:
Prices along the Gulf Coast rise ahead of forecasts of freezing temperatures. This report week (Wednesday, January 26 to Wednesday, February 2), the Henry Hub spot price rose $2.07 from $4.37 per million British thermal units (MMBtu) last Wednesday to $6.44/MMBtu yesterday. The increase was due to anticipation of winter storms sweeping across the country and colder-than-average temperatures throughout much of the Southeast and Texas. Yesterday’s increase was the biggest single-day rise in price since February 11, 2021, when prices rose in advance of a major winter storm that affected much of the Gulf Coast. Starting Friday, delivery of feed gas to Venture Global’s Calcasieu Pass LNG terminal began to rise above the approximate 30 million cubic feet per day (MMcf/d) average they reported for the first four weeks of January. Nominations on the TransCameron Pipeline rose to almost 110 MMcf/d on Saturday, and reached an all-time high of 133 MMcf/d on Tuesday. Calcasieu Pass received approvals on January 12, January 21, and January 27 from the Federal Energy Regulatory Commission (FERC) to introduce feed gas into various blocks of the facility as part of the commissioning process. On January 28, Venture Global received FERC approval to commission a loading jetty and a system to handle boil-off gas at the terminal. Altogether, the terminal will have 18 liquefaction trains capable of processing 1.5 billion cubic feet per day (Bcf/d) of feed gas into LNG when all units are completed towards the middle of the year. IHS Markit estimates feed gas deliveries to other LNG terminals in Southern Louisiana fell this report week, resulting in an aggregate decline of 0.7 Bcf/d this week to 6.7 Bcf/d. Heavy fog led to temporary closures of major waterways serving LNG export terminals, which may have contributed to lower LNG exports this week compared with last week. The LNG section below provides more details on LNG exports.
Prices in the Midwest increase in line with price increases at the Henry Hub. At the Chicago Citygate, the price increased $2.07 from $4.26/MMBtu last Wednesday to $6.33/MMBtu yesterday. IHS Markit reports consumption in the Midwest fell by 4.0 Bcf/d (17%) this report week to a daily average of 20.0 Bcf/d, primarily as a result of decreased consumption in the residential and commercial sector, which fell by 3.2 Bcf/d (20%). Temperatures in the Chicago area averaged 24°F this report week, about 1°F below normal, resulting in 284 heating degree days (HDDs, a measure of heating demand), compared with 357 last report week, when temperatures averaged 14°F (more than 11°F below normal).
Prices rise in the West in response to cooler temperatures, increased consumption, and reduced supply. The price at PG&E Citygate in Northern California rose $1.65, up from $4.94/MMBtu last Wednesday to $6.59/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $3.70 from $5.08/MMBtu last Wednesday to $8.78/MMBtu yesterday. NOAA reports temperatures at Riverside, California, inland from Los Angeles, averaged 55°F this report week, resulting in 66 HDDs, 30 HDDs more than last week. Prices also rose in all major supply areas serving Northern California. The price at the Opal Hub in southwest Wyoming, which serves as a source of natural gas into the Northern California market via the Ruby pipeline, rose $2.65 from $4.68/MMBtu last Wednesday to $7.33/MMBtu yesterday. The price at Cheyenne Hub in southeast Wyoming rose $2.72 from $4.24/MMBtu last Wednesday to $6.96/MMBtu yesterday. The price at Malin, Oregon, the northern delivery point into the PG&E service territory, rose $1.57 from $4.65/MMBtu last Wednesday to $6.22/MMBtu yesterday. IHS Markit estimates weekly average residential and commercial consumption in California increased by over 300 MMcf/d (10%) this report week, while natural gas consumption in the Pacific Northwest for all sectors increased by almost 200 MMcf/d (7%). Over the same period, IHS estimates supply decreased 629 MMcf/d (6%) for California and the Pacific Northwest combined. Kinder Morgan, operator of the El Paso Natural Gas (EPNG) pipeline, released an updated maintenance schedule showing maintenance on the Line 2000 segment through the Cimarron compressor station will continue through the end of February. This follows the force majeure notice issued by Kinder Morgan on Wednesday, January 19, which stated that "EPNG does not have a timeframe for bringing Line 2000 back to full service."
Prices in the Northeast decrease for the second consecutive week in between winter storms. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $5.85 from $20.71/MMBtu last Wednesday to $14.86/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased $5.13 from $11.92/MMBtu last Wednesday to $6.79/MMBtu yesterday. The Northeast experienced a brief warming trend this week, in between the massive winter storm last weekend and the upcoming winter storm forecasted for this weekend in the region. Total natural gas consumption decreased 3% (1.0 Bcf/d) to 31.3 Bcf/d from a week ago, according to data from IHS Markit.
According to Enbridge, operator of the Algonquin Gas Transmission (AGT) natural gas pipeline, sendout from the Northeast Gateway LNG terminal into their pipeline system averaged 80 MMcf/d during this report week. The Exemplar, a Floating Storage Regasification Unit (FSRU), started discharging on January 12, and has delivered to date 1.4 Bcf of LNG into the New England market. The highest daily sendout was on January 21, when the vessel discharged 377 MMcf. An estimated 1.6 Bcf of LNG remains onboard in the ship’s LNG storage tanks.
Prices in the Appalachia production region increase in line with rising prices across the country. The Tennessee Zone 4 Marcellus spot price increased $1.70 from $4.03/MMBtu last Wednesday to $5.73/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose $1.73 from $4.02/MMBtu last Wednesday to $5.75/MMBtu yesterday. According to IHS Markit, local natural gas consumption in the Appalachia production area decreased 7% (1.0 Bcf/d) to 12.9 Bcf/d from a week ago. Lower consumption in the region was offset in part by a 16% increase (0.6 Bcf/d) in southbound flows, which averaged 4.4 Bcf/d this report week. Natural gas production in the region was relatively flat at 32.7 Bcf/d.
The price in the Permian production region rises above Henry Hub with the onset of colder temperatures. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose $3.22 this report week from $4.04/MMBtu last Wednesday to $7.26/MMBtu yesterday. The Waha hub traded 82 cents above the Henry Hub price yesterday, compared with last Wednesday when it traded 33 cents below the Henry Hub price. The spot price rose in response to rapidly falling temperatures and anticipated disruptions to production caused by freeze-offs. Natural gas suppliers notified the Electric Reliability Council of Texas (ERCOT) of potential natural gas delivery curtailments due to expected freezing temperatures in the West Texas producing region. The low temperature in the Midland-Odessa area was 20°F yesterday, 14°F below the normal low for the day. Weather forecasts for the Midland-Odessa area show temperatures remaining well below freezing through the end of the week. IHS Markit reports natural gas production in the Permian region averaged 14.5 Bcf/d this report week, 3% above last week. However, based on pipeline flows estimates, IHS Markit expects that production will fall approximately 2.9 Bcf/d today.
U.S. natural gas supply is relatively flat this week. The average total supply of natural gas rose this week by 0.1% (0.1 Bcf/d) compared with the previous report week, according to data from IHS Markit. Dry natural gas production grew by 0.7% (0.6 Bcf/d) and was largely offset by lower net imports from Canada, which decreased by 6.0% (0.4 Bcf/d) from last week.
U.S. natural gas consumption falls across all sectors this week. Total U.S. consumption of natural gas fell by 7.7% (8.6 Bcf/d) compared with the previous report week, according to data from IHS Markit. Natural gas consumption in all sectors is lower this week, the largest decline being in the residential and commercial sector, where consumption fell by 9.6% (5.4 Bcf/d). Average temperatures, though below normal, rose relative to last week across the Lower 48 states. Natural gas consumed for power generation declined by 8.5% (2.5 Bcf/d) week over week, and industrial sector consumption decreased by 2.9% (0.7 Bcf/d). Natural gas exports to Mexico decreased 4.6% (0.3 Bcf/d) and natural gas deliveries to LNG export facilities averaged 12.1 Bcf/d, or 0.6 Bcf/d lower than last week.
U.S. LNG exports are down by three vessels this week from last week. Twenty-two LNG vessels (nine from Sabine Pass, four each from Corpus Christi and Freeport, three from Cameron, and two from Cove Point) with a combined LNG-carrying capacity of 81 Bcf departed the United States between January 27 and February 2, 2022, according to shipping data provided by Bloomberg Finance, L.P. In January, 103 tankers departed the United States, compared with 102 in December 2021. Vessel departures recorded for these two months were the highest to date.
Storage:
The net withdrawals from storage totaled 268 Bcf for the week ending January 28, compared with the five-year (2017–2021) average net withdrawals of 150 Bcf and last year's net withdrawals of 183 Bcf during the same week. Working natural gas stocks totaled 2,323 Bcf, which is 143 Bcf lower than the five-year average and 393 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 withdrawals of 263 Bcf to 297 Bcf, with a median estimate of 280 Bcf.
The average rate of withdrawals from storage is 3% higher 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 12.9 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,523 Bcf on March 31, which is 143 Bcf lower than the five-year average of 1,666 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, 27-Jan |
Fri, 28-Jan |
Mon, 31-Jan |
Tue, 01-Feb |
Wed, 02-Feb |
|---|---|---|---|---|---|
| Henry Hub |
4.45 |
5.63 |
5.58 |
5.46 |
6.44 |
| New York |
8.50 |
19.64 |
6.25 |
6.13 |
6.79 |
| Chicago |
4.43 |
5.12 |
5.08 |
5.32 |
6.33 |
| Cal. Comp. Avg.* |
4.85 |
5.29 |
5.38 |
5.84 |
7.03 |
| Futures ($/MMBtu) | |||||
| March contract | 6.265 |
4.639 |
4.874 |
4.751 |
5.501 |
| April contract |
4.283 |
4.473 |
4.675 |
4.573 |
5.044 |
| *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: (1/27/22 - 2/2/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 105.4 |
104.5 |
103.0 |
| Dry production | 93.6 |
93.0 |
92.0 |
| Net Canada imports | 6.6 |
7.0 |
6.8 |
| LNG pipeline deliveries | 0.3 |
0.4 |
0.3 |
| Total supply | 100.5 |
100.3 |
99.0 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| U.S. natural gas consumption - Gas Week: (1/27/22 - 2/2/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 102.7 |
111.4 |
102.4 |
| Power | 26.6 |
29.0 |
28.6 |
| Industrial | 25.2 |
25.9 |
25.3 |
| Residential/commercial | 51.0 |
56.4 |
48.6 |
| Mexico exports | 5.6 |
5.9 |
5.8 |
| Pipeline fuel use/losses | 7.4 |
7.7 |
7.3 |
| LNG pipeline receipts | 12.1 |
12.7 |
10.8 |
| Total demand | 127.8 |
137.6 |
126.3 |
|
Source: Chart by the U.S. Energy Information Administration (EIA), based on data from IHS Markit | |||
| Rigs | |||
|---|---|---|---|
Tue, January 25, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 495 |
0.8% |
67.8% |
| Natural gas rigs | 115 |
1.8% |
30.7% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, January 25, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 21 |
-8.7% |
-4.5% |
| Horizontal | 553 |
1.7% |
60.8% |
| Directional | 36 |
-2.7% |
100.0% |
| 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 | 2022-01-28 |
2022-01-21 |
change |
|
| East | 541 |
609 |
-68 |
|
| Midwest | 616 |
701 |
-85 |
|
| Mountain | 133 |
143 |
-10 |
|
| Pacific | 196 |
201 |
-5 |
|
| South Central | 837 |
938 |
-101 |
|
| Total | 2,323 |
2,591 |
-268 |
|
|
Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (1/28/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 590 |
-8.3 |
557 |
-2.9 |
|
| Midwest | 728 |
-15.4 |
669 |
-7.9 |
|
| Mountain | 160 |
-16.9 |
141 |
-5.7 |
|
| Pacific | 263 |
-25.5 |
217 |
-9.7 |
|
| South Central | 976 |
-14.2 |
883 |
-5.2 |
|
| Total | 2,716 |
-14.5 |
2,466 |
-5.8 |
|
| Source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jan 27) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 318 |
43 |
60 |
0 |
0 |
0 |
||
| Middle Atlantic | 314 |
51 |
68 |
0 |
0 |
0 |
||
| E N Central | 347 |
52 |
70 |
0 |
0 |
0 |
||
| W N Central | 340 |
28 |
36 |
0 |
0 |
0 |
||
| South Atlantic | 215 |
34 |
69 |
2 |
-6 |
-8 |
||
| E S Central | 225 |
39 |
96 |
0 |
-1 |
0 |
||
| W S Central | 164 |
28 |
87 |
0 |
-4 |
-5 |
||
| Mountain | 227 |
-1 |
-6 |
0 |
-1 |
0 |
||
| Pacific | 104 |
-11 |
-46 |
0 |
-1 |
0 |
||
| United States | 252 |
30 |
43 |
0 |
-2 |
-2 |
||
|
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 Jan 27, 2022
Source: National Oceanic and Atmospheric Administration Note: Image is not available.
Deviation between average and normal (°F)
7-day mean ending Jan 27, 2022
Source: National Oceanic and Atmospheric Administration Note: Image is not available.
