In the News (EIA):
New infrastructure increases takeaway capacity out of West Texas:
Recent completions of pipeline projects in Texas and Mexico have increased natural gas transportation capacity from the Waha Hub—located near Permian Basin production activities in West Texas—to the Gulf Coast and to Mexico. Two completed projects in Texas, along with two completed projects in Mexico, all help improve connectivity between neighboring markets and the Permian Basin, an area in which production has exceeded available takeaway capacity during the past few years. The recently completed projects include: Kinder Morgan’s 2.1 billion cubic feet per day (Bcf/d) Permian Highway Pipeline (PHP), which entered service in January. The PHP delivers natural gas from the Waha Hub to Katy, Texas, located near the Texas Gulf Coast, with additional connections to Mexico. The PHP joins Kinder Morgan’s 2.0 Bcf/d Gulf Coast Express, which entered service in September 2019 and delivers natural gas from the Waha area to Agua Dulce, Texas. Whitewater/MPLX’s Agua Blanca Expansion Project, which entered service in late January. The Agua Blanca Expansion Project connects to nearly 20 natural gas processing sites in the Delaware Basin and can move 1.8 Bcf/d of natural gas to the Waha Hub. The project will also connect with the Whistler Pipeline, which is scheduled to be completed in the third quarter of 2021, and would move an additional 2.0 Bcf/d of natural gas from the Permian Basin to the Texas Gulf Coast. Carso Energy’s 0.5 Bcf/d Samalayuca – Sásabe pipeline, which had its first commercial flows of natural gas in late January. The pipeline, located in Northwest Mexico, provides a more direct route for natural gas from the Permian Basin to serve this regional market. Fermaca’s 0.9 Bcf/d Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline, which began commercial operations in October 2020. The pipeline, located in Central Mexico, is the final segment of the Wahalajara system that connects the Waha Hub to Guadalajara and other population centers in west-central Mexico. With its completion, natural gas flows on the Trans-Pecos Pipeline, the first leg of the Wahalajara system connecting the Waha Hub to Mexico’s pipeline system, increased from about 0.3 Bcf/d to 0.6 Bcf/d. The additional takeaway capacity from these recently completed projects has contributed to U.S. pipeline exports to Mexico rising 0.55 Bcf/d (9.9% increase) to 5.9 Bcf/d from March 2020 to March 2021, according to the latest data available from the Natural Gas Monthly. Estimates from IHS Markit indicate high export volumes continued in April and May, averaging about 6.1 Bcf/d, a 31% increase from last April and May. The increase in takeaway capacity has also helped increase the natural gas price at the Waha Hub, narrowing its price difference (also known as the basis) to the Henry Hub. Over the past few years, constrained takeaway capacity in the Permian Basin has resulted in a wide basis relative to the Henry Hub as Waha prices consistently remained $1 per million British thermal units (MMBtu) or more below the Henry Hub price. However, beginning in late October 2020, the Waha-Henry Hub basis began narrowing significantly, and the price at the Waha Hub averaged only $0.22/MMBtu less than the Henry Hub price from March through May 2021. The most recent time that the basis was so narrow for a sustained period of time was in the spring of 2020, following a large decline in the price of crude oil and a concurrent decline in natural gas production, which increased the price at the Waha Hub.
Natural gas spot price movements were mixed this report week (Wednesday, May 26 to Wednesday, June 2). The Henry Hub spot price rose from $2.88 per million British thermal units (MMBtu) last Wednesday to $3.05/MMBtu yesterday. The June 2021 NYMEX contract expired last Wednesday at $2.984/MMBtu. The July 2021 contract price increased to $3.075/MMBtu, up 5¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging July 2021 through June 2022 futures contracts climbed 5¢/MMBtu to $3.049/MMBtu. The net injections to working gas totaled 98 billion cubic feet (Bcf) for the week ending May 28. Working natural gas stocks totaled 2,313 Bcf, which is 14% lower than the year-ago level and 3% lower than the five-year (2016–2020) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 38¢/MMBtu, averaging $7.95/MMBtu for the week ending June 2. The weekly average price of ethane increased 3%, in line with rising ethylene prices, which also rose 3% week over week. The price of propane rose 7%, as continuing strong exports and high domestic consumption (reported as product supplied) keep inventory builds below seasonal averages for this time of year. The prices of normal butane, isobutane, and natural gasoline rose by 4%, 5%, and 4%, respectively, in line with rising Brent crude oil prices, which rose by 4% week over week. According to Baker Hughes, for the week ending Tuesday, May 25, the natural gas rig count decreased by 1 to 98, with a 3-rig decline in the Pennsylvania section of the Marcellus play, offset by a 1-rig gain in non-Marcellus Pennsylvania. Although the natural gas rig count declined for the third week in a row, it remains 22 rigs above the same week last year. The number of oil-directed rigs rose by 3 to 359, led by a 3-rig gain in the Permian play in Texas. At 359, the oil-directed rig count continues to advance, rising for the fourth week in a row to the highest level since the last week of April 2020. The total rig count increased by 2, and it now stands at 457.
Henry Hub prices rise in anticipation of elevated demand as a result of well-above-normal temperatures across most of the Lower 48 states. This report week (Wednesday, May 26 to Wednesday, June 2), the Henry Hub spot price rose 17¢ from $2.88/MMBtu last Wednesday to $3.05/MMBtu yesterday. Henry Hub prices held steady most of last week, at between $2.84/MMBtu and $2.88/MMBtu through Friday. Prices rose to $2.97/MMBtu on Monday before reaching a report-week high of $3.05/MMBtu yesterday, following expectations of a heat wave across most of the Lower 48 states east of the Rockies and relatively high exports to tighten the market. Midwest prices rise rapidly as expected demand for power generation increases because of unusually warm weather. At the Chicago Citygate, the price increased 16¢ from $2.81/MMBtu last Wednesday to $2.97/MMBtu yesterday. The Natural Gas Intelligence Midwest Regional Average price increased 18¢ from $2.74/MMBtu last Wednesday to $2.92/MMBtu yesterday. Both pricing indexes rose rapidly on Tuesday and Wednesday of this report week as a heat wave moved east from the Rockies into the Midwest, resulting in elevated air conditioning demand and related rise in natural gas consumption for electricity generation. Temperatures in the Western Plains rose into the 90s yesterday, with Bismark, North Dakota, reporting a high of 90°F, 16°F above normal. As the front moves east, temperatures in major consumption centers across the Midwest will also likely rise into the 90s today through Saturday. Prices in California rise, as temperatures increase above 100°F across a large swath of the region. The price at PG&E Citygate in Northern California rose 30¢, up from $3.75/MMBtu last Wednesday to a weekly high of $4.05/MMBtu yesterday. Temperatures in Northern California rose well above normal for this time of year, exceeding 100°F, on average 15°F above normal. Temperatures in Bakersfield, California, reached a daily high of 106°F yesterday, 17°F above normal and just 3°F below the all-time high set in 1970. At Montague, California, on the California-Oregon border, temperatures reached 103°F yesterday, 25°F above normal and 7°F above the all-time record set in 1960. IHS Markit reports average California natural gas consumption for power generation rose 50% week over week and exceeded 2.2 billion cubic feet per day (Bcf/d) yesterday, the highest level for the start of June since 2016. The price at SoCal Citygate in Southern California increased 38¢ from $4.10/MMBtu last Wednesday to $4.48/MMBtu yesterday, after reaching a weekly high of $4.92/MMBtu on Tuesday. Prices in the regions supplying SoCalGas rose week over week. Prices on the El Paso S. Mainline/N. Baja, which serves delivery points in Arizona, rose 66¢, from $2.71/MMBtu last Wednesday to $3.37/MMBtu yesterday, as temperatures in the region approached record highs. Temperatures in Phoenix, Arizona, reached a daily high of 106°F yesterday, just 4°F below the all-time high set in 1977. In addition, the El Paso Natural Gas pipeline reports constraints at delivery points into the SoCalGas region, causing average prices at the Natural Gas Intelligence Southern California border to rise $0.46/MMBtu week over week—from $2.85/MMBtu last Wednesday to $3.31/MMBtu yesterday—following a weekly high of $3.46/MMBtu on Tuesday, the highest level since mid-February. Northeast prices decrease as mild weather results in lower consumption. At the Algonquin Citygate, which serves Boston-area consumers, the price went down 7¢ from $2.30/MMBtu last Wednesday to $2.23/MMBtu yesterday. Temperatures in New England were slightly above normal for this time of year, with Boston averaging 69°F yesterday. Temperatures in New York City were also mild yesterday, averaging 69°F. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price decreased 23¢ from $2.41/MMBtu last Wednesday to $2.18/MMBtu yesterday. Prices at both Algonquin Citygate and Transco Zone 6 reached weekly lows on Tuesday, at $1.92/MMBtu and $2.20/MMBtu, respectively. Prices in the Appalachian Basin production region fall as pipeline capacity constraints reduce flows out of the region. The Tennessee Zone 4 Marcellus spot price decreased 56¢ from $2.05/MMBtu last Wednesday to $1.49/MMBtu yesterday. The price at Eastern Gas South (formerly known as Dominion South as of June 1, 2021) in southwest Pennsylvania fell 22¢ from $2.23/MMBtu last Wednesday to $2.01/MMBtu yesterday. The Enbridge-operated Texas Eastern natural gas pipeline declared a force majeure on its 30-inch pipeline south in response to a Pipeline and Hazardous Materials Administration (PHMSA) order to reduce pipeline pressure by 20%, which resulted in capacity reduction for southbound flows out of the Berne, Ohio, compressor station by more than 0.7 Bcf/d, from 2.0 Bcf/d reported by Texas Eastern on May 31 to 1.3 Bcf/d reported for June 2. The PHMSA order took effect June 1, with no specified end date. Prices in the Permian production region in West Texas rise week over week, pulled up by increased prices in demand regions. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 43¢/MMBtu, from $2.51/MMBtu last Wednesday to $2.91/MMBtu, in response to strong demand in markets (see Southern California discussion above). The discount at Waha relative to the Henry Hub declined from 37¢/MMBtu last Wednesday to 14¢/MMBtu this Wednesday. U.S. dry natural gas production continues to increase. According to data from IHS Markit, the average total supply of natural gas fell slightly by 0.4% compared with the previous report week. Dry natural gas production grew by 0.2% compared with the previous report week to 92.6 Bcf/d, the highest weekly average since the second week of April 2020, according to data from IHS Markit. Average net imports from Canada decreased by 13.5% from last week amid the start of a planned service outage of the Viking pipeline this week. U.S. natural gas consumption increases driven by the residential and commercial sectors. Total U.S. consumption of natural gas rose by 0.7% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 8.0% this week after a 15.4% increase last week. Industrial sector consumption increased by 2.7% week over week. In the residential and commercial sectors, consumption increased by 24.0% as Memorial Day weekend temperatures in the Midwest and Northeast were much lower than normal. Natural gas exports to Mexico increased 3.8%, to 6.4 Bcf/d. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 10.9 Bcf/d, or 0.42 Bcf/d higher than last week. U.S. LNG exports increase week over week. Twenty-one LNG vessels (seven from Sabine Pass, four each from Freeport and Cameron, three from Corpus Christi, two from Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 76 Bcf departed the United States between May 27 and June 2, 2021, according to shipping data provided by Bloomberg Finance, L.P.
The net injections into storage totaled 98 Bcf for the week ending May 28, compared with the five-year (2016–2020) average net injections of 96 Bcf and last year’s net injections of 103 Bcf during the same week. Working natural gas stocks totaled 2,313 Bcf, which is 61 Bcf lower than the five-year average and 386 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 86 Bcf to 112 Bcf, with a median estimate of 96 Bcf. The average rate of injections into storage is 6% lower than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 8.6 Bcf/d for the remainder of the refill season, the total inventory would be 3,658 Bcf on October 31, which is 61 Bcf lower than the five-year average of 3,719 Bcf for that time of year.