LNG

The US government reported that the increase in the nation’s liquefied natural gas exports was supported by large prices differences between the benchmark Henry Hub and spot prices in Europe and Asia and forecast a surge in shipments through March 2022.

The US government forecasts a slight decline in US liquefied natural gas exports in May 2021 before they rise again in the Northern Hemisphere summer months to meet continued demand in Europe and Asia.

Natural gas use for LNG is expected to be around 8.6 billion cubic feet per day, more than 90 percent of baseload export capacity utilization in May, before increasing to above 9.0 Bcf per day, according to the short-term outlook of the US Energy Information Administration.

“We expect LNG exports will average 9.2 Bcf per day in both 2021 and 2022, up from 6.5 Bcf per day in 2020,” said the report.

On US production, the EIA forecasts output of dry natural gas would average 91.1 Bcf per day in 2021, which is a decline of 0.3 percent from 2020.

The report estimated that production increased to 91.3 Bcf per day in March, though it forecast relatively flat dry natural gas production in May ahead of production beginning to rise in mid-2021.

“We forecast dry natural gas production will reach 92.0 Bcf per day in the fourth quarter of 2021 and average 93.1 Bcf per day in 2022,” the report added.

“The increase in production reflects sustained higher forecast prices for natural gas and crude oil compared with 2020,” said the EIA.

Working gas storage

On the storage front, the EIA estimated that natural gas inventories at the end of April 2021 were almost 2.0 trillion cubic feet (Tcf), which was 3 percent lower than the five-year (2016-2020) average.

“Natural gas withdrawals from storage during the winter of 2020-2021 were higher than the five-year average, largely as a result of the cold February temperatures that contributed to a drop in natural gas production,” the report explained.

“We forecast that natural gas inventories will end the 2021 injection season (end of October 2021) at more than 3.6 Tcf, which is 3 percent below the five-year average,” said the EIA.

On the Henry Hub spot price, the report expected that it would average $2.78 per million British thermal units in the second quarter of 2021 and would average $3.05 per MMBtu for all of 2021, which is up from the 2020 average of $2.03 per MMBtu.

“We expect natural gas prices will rise this year, primarily as a result of two factors, the growth in LNG exports and rising domestic natural gas consumption in the residential, commercial and industrial sectors,” it said.

The EIA forecasts that in the 2022, the Henry Hub price would decline slightly to an average $3.02 per MMBtu “amid slowing growth in LNG exports and rising production” of natural gas.

Natural gas storage in the United States has remained essentially unchanged in more than a year with underground working gas capacity in the Lower 48 states showing a small increase in design capacity and peak capacity having a small decrease.

Design capacity by state showed the largest is in Texas at 526 billion cubic feet followed by Louisiana at 451 Bcf then Pennsylvania in third place with 418 Bcf and California is in fourth with 374 Bcf. Illinois came fifth with 301 Bcf and sixth place was filled by Ohio with 253 Bcf.

“Design capacity, sometimes referred to as nameplate capacity, is based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which often must be certified by federal or state regulators,” explained a report on underground natural gas storage just published by the Energy Information Administration.

“We calculated design capacity as the sum of the reported working natural gas capacities of the 387 active storage fields in the Lower 48 states,” said the EIA.

“We excluded the 25 inactive fields in the Lower 48 states from the total. The design capacity metric is a theoretical limit on the total amount of natural gas that can be stored underground and withdrawn for use,” it added.

Demonstrated peak capacity, or total demonstrated maximum working natural gas capacity, represents the sum of the largest volume of working natural gas reported for each individual storage field during the most recent five-year period, regardless of when the individual peaks occurred.

Estimates

Natural gas design capacity was essentially unchanged in 2020. However, some operators revised earlier estimates, increasing working gas capacity.

Design capacity of underground natural gas storage facilities in the Lower 48 states increased by 4 Bcf, or 0.1 percent, in the November 2020 report period compared with the November 2019 period.

A couple of notable revisions increased working gas capacity reported for 2019 in the Mountain and Pacific regions, which reflects the operators’ reassessments of the operational characteristics of the affected fields.

Increasing exports of natural gas also could increase natural gas storage capacity in the Gulf Coast region to support pipeline exports of natural gas to Mexico and LNG exports.

“Working gas stocks ended the November 2020 report period at its highest level since 2016, despite decreased natural gas production and continued high demand for natural gas in electricity generation and for export,” said the US report.

“The higher natural gas storage level was partly because working gas entered the refill season, in April, at 2,006 Bcf, ts highest level since 2017, following a relatively mild winter.

In the Mountain region, Spire Storage West revised the working gas capacity at the Belle Butte field (formerly Ryckman Creek) up by 16 Bcf to 35 Bcf.

South Central

Working natural gas design capacity increased by 5 Bcf in the South Central region. The most notable increase in the region was the 4.2 Bcf gain reported for the Egan Storage Dome by Egan Hub Partners.

Dewatering the salt cavern raised the capacity of this field.

In the Pacific region, the Northwest Natural Gas Company revised the working gas capacity for the Mist field in Oregon, increasing capacity by 1.5 Bcf to 4 Bcf for 2019.

The North Mist capacity expansion came online in May 2019.

Northwest Natural revised its early estimates of the design capacity of the Mist field, the only new natural gas storage reservoir to come online in 2019, based on the observed operational characteristics of the facility. Working gas capacity remained unchanged at the facility in 2020.

Demonstrated peak capacity decreased in 2020 as the decline in the Pacific region more than offset gains reported in other regions.

Overall, demonstrated peak capacity declined by 8 Bcf, despite reported increases in five of six regions in the Lower 48 states as of the November 2020 report period compared with the November 2019.

“Despite the net decline in demonstrated peak capacity for the Lower 48 states, the overall trend was toward increased usage of natural gas storage and higher working natural gas storage levels for the second year in a row,” said the report.

Peak capacity

Demonstrated peak capacity declined by 34 Bcf in the Pacific region because previous peak levels, predating the 2015 natural gas leak at the Aliso Canyon natural gas storage facility in California, are no longer included in the five-year range (December 2015-November 2020).

The Aliso Canyon field has operated at reduced levels since coming back online following the leak. Despite the decline in demonstrated peak capacity for the region, natural storage facilities in the Pacific region also saw increased usage during 2020 as in the other regions.

The South Central region reported the biggest increase in demonstrated peak capacity in 2020, increasing 10 Bcf (0.7 percent) over the previous year.

Salt facilities accounted for 8 Bcf of this year-over year increase. The Midwest had the next largest increase at 7 Bcf, followed by the Mountain region at 7 Bcf and the East region at 3 Bcf.

In recent years, several offsetting trends have affected the industry’s decisions about changes to underground storage capacity levels. Several recent trends may have reduced the need for investment in additional underground storage.

Although natural gas production declined in 2020, overall higher levels of natural gas production compared with a few years ago may have reduced some customers’ need to withdraw from storage to meet their natural gas needs.

The EIA stated that increased output in the Appalachian Basin, the Permian Basin and the Haynesville shale formation had driven production growth.

“In recent years, natural gas prices have fallen and become less volatile,” it also noted.

The seasonal spread between summer and winter natural gas prices has become increasingly smaller, reducing economic incentives to inject natural gas into reservoir and aquifer storage.

New plans

Among new storage plans on the Gulf Coast Sempra Energy’s storage unit in February 2021 gave more details of plans to construct and operate a “high-deliverability” salt-dome natural gas storage facility in Louisiana for existing and proposed LNG export plants with interconnections to key pipelines.

The applicant-prepared environmental assessment for the Hackberry Storage Project submitted to the Federal Energy Regulatory Commission gives full details of the storage facilities in Cameron Parish capable of providing 20.03 Bcf of working gas capacity and 1.5 Bcf per day of LNG feed gas.

LA Storage is leading the project and is a wholly-owned subsidiary of Liberty Gas Storage, ultimately held by Sempra LNG, operator of the Cameron LNG export plant, and parent Sempra Energy.

The storage facility would interconnect with infrastructure operated by Cameron Interstate Pipeline and the certificated Port Arthur Pipeline Louisiana Connector to be operated by Port Arthur Pipeline in Cameron and Calcasieu Parishes in Louisiana.

The interconnection of the Hackberry Storage Project with these pipelines would in turn provide customer access among interstate pipelines serving the Gulf Coast market and natural gas markets along the Southeast and East Coasts.

LA Storage proposes to construct a new natural gas storage facility by converting three existing salt-dome caverns to natural gas storage service and developing one new salt-dome cavern for additional natural gas storage service.

The United States expects liquefied natural gas exports to average 6.6 billion cubic feet per day in the second quarter of 2020 before declining in the third quarter.

The US will have ample natural gas to divert to the export market as LNG now and in the future because of several issues such as its ability to post record storage numbers over the past 12 months that saw weekly inventories surpassing five-year highs in 48 weeks of the previous 52 weeks.