Rising domestic and international demand for natural gas as winter weather settles in, combined with continued light production levels, are expected to send U.S. natural gas prices soaring next year, according to multiple forecasts issued in recent days.
In its latest Short-Term Energy Outlook (STEO) published October 6, the U.S. Energy Information Agency said it expects monthly average spot prices will remain higher than $3.00/MMBtu throughout 2021, averaging $3.13 for the year, up from a forecasted average of $2.07 for 2020.
Although U.S. natural gas storage inventories are expected to exceed 4.0 Tcf by the end of October, setting a new record, the surplus is expected to be short-lived as low crude prices keep associated gas output from oil-directed rigs at levels lower than before the coronavirus pandemic.
“Because expected natural gas production will be lower this winter than last winter, EIA forecasts inventory draws will outpace the five-year average during the heating season and end March 2021 at 1.7 Tcf, which would be 6% lower than the 2016–20 average,” researchers said.
Raymond James & Associates Inc. analysts expressed an even more bullish view on Monday, forecasting an average Henry Hub price of $3.50/MMBtu for 2021.
Morgan Stanley analysts, meanwhile, said last week that record production declines and a rebound in winter heating demand could propel Henry Hub prices to $5.00/MMBtu if weather is colder than normal this winter.
Natural gas prices in Mexico are closely tied to U.S. prices, given Mexico’s growing reliance on pipeline gas imports from its neighbor to the north.
Pipeline gas flows from the United States to Mexico, which have stayed resilient through the pandemic, are poised for continued growth, particularly out of West Texas, following the entrance into commercial service of the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline.
VAG is the final section of the Waha-to-Guadalajara or “Wahalajara” pipeline system developed by Mexican company Fermaca.
“While exports to Mexico from Waha will average about 0.6 Bcf/d this year, current flows are up to 0.8 Bcf/d and are expected to head higher in the years ahead,” said RBN Energy LLC analyst Jason Ferguson in a research note on Sunday.
Ferguson also said that given the shift of most western U.S. states to non-fossil power generation, “about the only hope” for increased westward gas flows out of the Permian Basin would be the sanctioning of Sempra Energy’s Energía Costa Azul liquefied natural gas (LNG) export project in Mexico’s Baja California state.
In September, EIA said Henry Hub spot prices averaged $1.92, down from an average of $2.30 in August. This “reflected declining demand for natural gas from the U.S. electric power sector as a result of cooler-than-normal temperatures during the second half of September and relatively low demand for U.S. liquefied natural gas (LNG) exports amid hurricane-related activity in the Gulf of Mexico.”
EIA estimated that U.S. LNG exports averaged 4.9 Bcf/d in September, an increase of 1.2 Bcf/d from August. However, August levels still reflected demand aftershocks from the pandemic.
“Higher global forward prices indicate improving netbacks for buyers of U.S. LNG in European and Asian markets for the upcoming fall and winter seasons,” EIA said. “The increased prices come amid expectations of natural gas demand recovery and potential LNG supply reductions because of maintenance at the Gorgon LNG plant in Australia.”
EIA now is forecasting LNG exports “will return to pre-Covid levels by November…and will average more than 9.0 Bcf/d” from December through February.
The latest forecast also calls for total U.S. gas consumption to average 83.7 Bcf/d in 2020, down 1.8% from 2019. The expected decline reflects lower heating demand in early 2020, contributing to residential demand averaging 13.1 Bcf/d, down 0.7 Bcf/d from 2019. Commercial demand is expected to average 8.7 Bcf/d, off 0.9 Bcf/d.
Industrial consumption is seen averaging 22.3 Bcf/d this year, down 0.8 Bcf/d year/year. EIA said the loss should result from reduced manufacturing activity amid the restrictions that governments imposed in the spring to slow spread of the virus.
EIA projected total U.S. gas consumption will average 78.7 Bcf/d in 2021, a 5.9% decline from 2020. “The expected decline in 2021 is the result of rising natural gas prices that will reduce demand for natural gas in the electric power sector,” researchers said.
U.S. dry natural gas production is forecast to average 90.6 Bcf/d, down from an average of 93.1 Bcf/d in 2019. The monthly average production is expected to fall from a record 97.0 Bcf/d last December to 85.9 Bcf/d in May 2021, before increasing slightly.
Gas production declines are expected to be highest in the Permian, “where EIA expects low crude oil prices will reduce associated natural gas output from oil-directed rigs” The dry gas production forecast in the United States is seen averaging 86.8 Bcf/d in 2021. Researchers anticipate production will “begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices.”
EIA said its latest STEO “remains subject to heightened levels of uncertainty” because mitigation efforts related to the pandemic continue to evolve. “Reduced economic activity related to the Covid-19 pandemic has caused changes in energy demand and supply patterns in 2020 and will continue to affect these patterns in the future.”
The latest outlook assumes U.S. gross domestic product (GDP) declined by 4.4% in the first half of 2020 from the same period in 2019. It also assumes that GDP began to rise in 3Q2020 and will grow 3.5% year-over-year in 2021.
Rising Oil Output
U.S. oil production, meanwhile, rose to an estimated 11.2 million b/d in September from 10.8 million b/d in August, EIA said. Production averaged 11.0 million b/d in July, up 0.5 million b/d from June.
In May, U.S. oil production reached a two-and-a-half-year low of 10.0 million b/d amid cratered oil prices after the pandemic crushed demand.
“Since then, U.S. production has increased mainly because tight oil operators have brought wells back online in response to rising prices,” researchers said. However, EIA expects oil production to taper in coming months and “generally decline to average of 11.0 million b/d in the second quarter of 2021 because new drilling activity will not generate enough production to offset declines from existing wells.
Drilling activity is forecast to rise later in 2021, contributing to U.S. oil production returning to 11.2 million b/d in the final three months of 2021.
On an annual average basis, EIA expects U.S. crude oil production to fall from 12.2 million b/d in 2019 to 11.5 million b/d in 2020 and 11.1 million b/d in 2021.
With additional reporting by Andrew Baker
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