March 2021, Vol. 248, No. 3
Features
Gas Storage Ups and Downs
By Danielle C. Roberts, P&GJ Contributor
When a nor’easter hammered the U.S. in late 2020, dumping a foot of snow over much of the region and depressing temperatures even in the South and Southwest, it netted a steep withdrawal of 152 Bcf (4.3 Bcm) natural gas storage for the week ending December 18.
“I don’t know how” a 152-Bcf pull vs. a 159-Bcf (4.5 Bcm) market expectation “crushes natural gas prices,” said one participant on The Desk’s online energy platform Enelyst. “Amazing.”
That kind of amazement isn’t typical in the natural gas storage market. But coming off a year that was anything but typical, it’s no surprise that gas storage – a key indicator of natural gas prices and an important market in the U.S. energy picture – has been impacted by the pandemic, but even more so, by demand growth, cancellation of major pipeline projects and the push for electrification and green energy.
Impact of 2020
In March of last year, traders and analysts were at a loss as COVID-19 placed markets worldwide in turmoil.
“A larger-than-expected inventory draw failed to inject any bullishness into the natural gas futures market,” wrote Jeremiah Shelor for Natural Gas Intelligence. “[And] in the spot market, widespread mild temperatures – and, perhaps, widespread social distancing – kept the pressure on prices as hubs from coast to coast saw discounts.”
Mild weather during the 2019-2020 winter season had already contributed to high storage inventories last spring.
In the wake of the spring COVID-19 shutdowns, “U.S. industrial and residential/commercial (res/comm) demand were impacted in April 2020,” said Karen Merkel, who sits in National Fuel’s Corporate Communications group.
“Not surprisingly, the Northeast has been most impacted, given restrictions in New York and New Jersey – the two states with the highest number of coronavirus cases at the time – followed by the Southeast and to a lesser extent the Midwest and Southwest.”
But the surplus would prove to be short-lived. By the final full week of 2020, gas in storage had fallen by a margin much higher than the five-year average – 123 Bcf (3.5 Bcm) compared to an average draw of 102 Bcf (2.9 Bcm). Vaccinations also began mid-December across the U.S., as a new administration was preparing to take office and demand drops had largely reversed.
While prices were still near $2.50/MMBtu at the time, that kind of pricing is not likely to continue into 2021 and beyond, predict analysts.
One of those is Andrew Weissman, chief executive officer of EBWAnalytics Group. “The market still thinks storage is adequate,” said Weissman at the end of January. “It’s going to find out very soon that it’s not … Basically, what’ll happen is that by the time we get into the fall, cash market prices [of gas] will be on the order of 50% higher than they are right now.”
The EIA has also forecast Henry Hub prices moving to $3.01/MMBtu in the first quarter of 2021. Raymond James & Associates Inc. suggested that prices could rise to $4/MMBtu by the end of the year. In late 2020, Morgan Stanley analysts warned that prices could go as high as $5/MMBtu.
Those price increases will have a strong downstream effect on the U.S. energy mix. Weissman predicts that electricity prices will experience a concurrent increase and, even more so, power sector emissions, which have been on a decline over the past decade.
“The single most important driver [of that] has been low natural gas prices,” he said. “[But] once prices get to the mid-$3 range, once they’re roughly 50% higher … utilization of gas to generate power will be down somewhere in the order of 10% to 15%. At least for the most part, it will be replaced by some pretty substantial increases in the use of coal-fired generation and actually along with that some fairly substantial increases in CO2 emissions.”
Case of Supply and Demand
About 15 years ago, total U.S. daily gas consumption was about 50 Bcf/d (1.4 Bcm/d). Today, that total is nearer 85 Bcf/d (2.4 Bcm/d). Consider this: In summer 2019, the U.S. set records in monthly electric power sector consumption of natural gas, at 41.1 Bcf/d (1.16 Bcm/d) in July and 41.6 Bcf/d (1.18 Bcm/d) in August.
Along with surging growth in gas-fired generation, countries around the world are hungry for U.S. gas. Liquefied natural gas facilities exported nearly 9 Bcf/d (255 MMcm/d) at the end of 2019, while exports to Mexico averaged 5.1 Bcf/d (144 MMcm/d); both are expected to increase.
Factor in the construction of several major U.S. petrochemical plants along the Gulf Coast and near the Marcellus Shale, said Weissman, along with a significant rise in residential consumption for space heating, and “it’s resulted in an all-time record demand for natural gas.”
Temperature swings are another major force that can’t be overlooked, said energy company Kinder Morgan.
According to a spokesperson, “Very hot, windless summer days and very cold, icy winter nights will drive new peaks in natural gas storage demand as gas-fired power plants fill in for the intermittent renewables and loss of baseload coal plants. Additionally, as more U.S. LNG export facilities come online, frigid winters in Asia and Europe will attract additional volumes toward these markets that are supported by Gulf Coast natural gas storage.”
Meanwhile, vast supplies are technically available. In September 2019, the Potential Gas Committee (PGC) released the results of its biennial assessment of U.S. natural gas resources, finding that the U.S. has a total mean technically recoverable resource base of 3,374 Tcf (95.55 Tcm) as of year-end 2018.
“This is the highest resource evaluation in the Committee’s 54-year history, exceeding the previous high assessment (from year-end 2016) by 557 Tcf (15.7 Tcm) (increase of about 20%). This is also the largest two-year increase in absolute resources between evaluations in the PGC history,” according to PGC. “The increase resulted from reassessments of shale gas resources in the Atlantic and Mid-Continent areas and conventional and tight gas in the Mid-Continent and Rocky Mountain areas.”
However, a bottleneck is potentially keeping vast gas supplies out of reach.
For one, low crude oil prices have led to reduced associated gas production, with the Organization for Economic Co-operation and Development (OECD) reporting in September, “On the demand side, containment measures and economic disruptions related to the COVID-19 outbreak have led to a slowdown in production and mobility worldwide, producing a significant drop in global demand for oil. In April, the International Energy Agency (IEA) estimated that demand was down 30% compared to a year ago, reaching a level not seen since 1995.”
Further limiting access to supply is last year’s cancellation of the Atlantic Coast Pipeline project and the new administration’s revocation of permits for the Keystone XL pipeline, both of which could put another major project, the Mountain Valley pipeline, in peril.
“Until 12 months ago, surging demand was satisfied by the very strong growth in production of associated gas and by huge increases in production in Marcellus Shale,” said Weissman. “All of a sudden, basically, we’re in a situation where the core demand for natural gas – before you take into account these price effects – is continuing to grow rapidly and now suddenly [has] hit a wall in terms of the supply available to the U.S. market. And the results of that is for at least the last nine months or so, we’ve basically been in a deficit position where we’re not producing as much gas as we need.”
Utilities will likely continue to be able to fill storage to near peak levels at the end of the injection seasons. But, said Weissman, that will happen because the utilities will pay high enough prices to drive other users out of the market. “The question is, how high?” he said.
Storage in Practice
Worldwide, the natural gas storage market is still anticipated to grow at a compound annual growth rate (CAGR) of almost 3% through 2023, according to Technavio, as demand for natural gas is still expected to rise across the globe over at least the next 20 years.
Gas storage is also expected to help meet requirements around the ongoing push for renewable energy.
“We believe that the importance of underground natural gas storage will grow as the percentage of power supplied by renewables increases. We also expect it to remain a critical long-duration energy storage solution to compensate for the limited duration of battery energy storage system technologies,” said a Kinder Morgan spokesperson. “We also see hydrogen storage in salt caverns as technically feasible and a future technology that could be used to balance the intermittent nature of renewables. Hydrogen can be safely and reliably stored in caverns for hours, days and years, providing the long-duration flexibility to meet future market demands.”
Merkel agrees. “National Fuel believes there could be a market to serve electric generation needs that work in conjunction with renewable power,” she said. “A storage service providing both injections and withdrawals on a year-round basis would have value in the green energy future. Clearly this would be a non-traditional service for National Fuel down the road.”
But are regulations and policies in place to support the necessary growth in storage?
“Frankly, no,” Weissman said. “Unfortunately, there are only limited number of places where you can even build storage and it’s a multiyear process … It’s going to be many years before we even have a modest increase in storage. And beyond that we definitely need more pipeline capacity from producing areas to demand areas. Realistically, we’re past the point in which that’s likely to occur … between the cancellation of Atlantic Coast and the potential demise of Mountain Valley and the cancellation of Keystone XL, nobody is going to build a pipeline outside of Texas or Louisiana.”
As natural gas prices rise, he emphasized again that companies will turn to alternate energy sources such as coal. In direct opposition to the goals of those against pipelines, the impact of reduced natural gas infrastructure will be enormous emissions growth. “I’ve actually tried to calculate it out, and essentially, the annual increase in CO2 emissions will basically cancel out the cumulative decrease in CO2 emissions in California over the last five years. It’s really quite substantial,” he said.
“I’m talking about a one-year increase canceling out five years of reductions, and that increase will continue year after year and will essentially negate at least 30% to 40% of all the emission reductions that have been achieved nationally as a result of wind and solar. It’s a big deal.”
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