A decade ago, many analysts warned that building liquefied natural gas export capacity in the U.S. would link domestic natural gas markets to global energy markets, resulting in negative impacts both on domestic supplies and prices.

Now, those 10-year-old warnings seem to be prescient. A handful of factors is keeping natural gas prices high just as the season for peak air conditioning load gets underway.

This year, however, Russia’s invasion of Ukraine complicates utility decision making as the U.S. joins with other nations to backstop world markets with natural gas that otherwise would be supplied by Russia. 

What’s more, transportation constraints in the U.S. are impacting coal deliveries to power plants.

All this comes as power industry watchers await the North American Electric Reliability Corp.’s annual summer reliability assessment.

Early hints raise worries. For example, the Mid-Continentent Independent System Operator (MISO) offered a blunt assessment of what it is expecting this summer. It said in late April that firm resources “will be insufficient to cover peak load of summer months.” It warned that emergency resources and non-firm energy imports “will be needed to maintain system reliability.” And it said that the need for emergency procedures will be impacted by the availability of non-firm resources.

What’s going on? A closer look at the Energy information Administration’s (EIA’s) latest Sort-Term Energy Outlook highlights three critical factors.

First, natural gas spot prices measured at the Henry Hub averaged $6.59 per million British thermal units (MMBtu) in April. That was up from the March average of $4.90/MMBtu. And the benchmark price was more than double the April 2021 average of $2.66/MMBtu. 

No relief is in sight: EIA said it expects Henry Hub to average $7.83/MMBtu during the second quarter and climb to an average $8.59/MMBtu in the second half.

By contrast, prices for coal produced from the Powder River Basin—the nation’s largest producing region—averaged $0.88/MMBtu as of May 13. That was for fuel with a heat rate of 8,800 Btu and a sulfur dioxide content of 0.8. Central Appalachian coal—with a heat rate of 12,500 Btu and a sulfur dioxide content of 1.2–averaged $5.03 as of mid-May. That average price was up $0.25 from a week earlier.

Keep in mind that since around 2011, economics have largely driven the decision to dispatch either natural gas-fired generation and coal-fired resources. The rise of hydraulic fracturing meant that plentiful supplies of low-cost natural gas could produce electricity more cheaply than coal. So today, with Henry Hub prices at levels not seen in decades, the safe bet would seem to be that coal-fired generation would benefit.

But that bet could be misplaced. Coal-fired power plants are having supply issues of their own, the second key factor that is complicating things for power plant operators.

During a late-April presentation to MISO, economic consultant Timothy Crowley of L.E. Peabody & Associates said that although coal traffic by America’s Class I railroads was up due to higher natural gas prices, any rebound for coal was likely to be short-lived. 

He said that given coal-fired generation’s generally bleak outlook as retirements continue to whittle away the fleet, railroads are unlikely to spend much either to expand or improve coal-hauling capacity. At the same time, however, higher electricity demand in 2021 depleted utility coal stockpiles. But, the current focus is on rebuilding stockpiles so rail transport constraints are unlikely to allow much upside for coal generators.

Crowley also pointed to a recent statement from Surface Transportation Board chair Martin Oberman, who blamed rail delivery problems on the railroads themselves, which cut employee headcount by 29%–or around 45,000 people—over the past six years. 

“On too many parts of their networks, the railroads simply do not have a sufficient number of employees,” Oberman said in April.

A third complicating factor is the uptick of liquefied natural gas (LNG) exports as the U.S.—along with other global suppliers—work to offset Russian natural gas deliveries to Europe, a result of the Ukraine invasion that began in February.

According to EIA, liquefied natural gas exports during April averaged 11.6 billion cubic feet per day (Bcf/d). That was just below an all-time peak of almost 12.0 Bcf/d set in March. And while LNG export price data since Russia’s invasion of Ukraine has yet to be reported, EIA said that in February LNG exports from U.S. terminals averaged $10.17/MMBtu, up from $%8.56/MMBtu in January.

Looking ahead, the government’s chief energy forecast agency said it expected LNG exports to average 12.1 Bcf/d from May through August, and average 12.0 Bcf/d through the end of the year. That would mark a 23% increase from 2021.

All of the LNG export capacity that has come online over the past decade means that domestic U.S. natural gas production is coupled like never before with global supply and demand. That means the war in Ukraine has an outsized impact on U.S. electricity production in just the sort of cause-and-effect way that analysts warned it would a decade ago. 

Beyond this summer, another factor will help determine the trajectory of natural gas-fired generation and electricity prices in 2023. Natural gas storage inventories ended April at 1.6 trillion cubic feet (Tcf), some 17% below the five-year average. 

EIA went on to say that natural gas inventories are likely to rise by 418 Bcf in May, ending at 2.0 Tcf. Even so, that mark would be 14% below the five-year average for this time of year. 

Looking forward, EIA is forecasting that natural gas inventories will end the 2022 injection season (end of October) at almost 3.4 Tcf, some 9% below the five-year average. And it warned that summer temperatures will be key, as is often the case. A hotter-than-normal summer that results in high electricity demand could cause natural gas inventories to shrink and prices to rise higher than forecast. 

Oh yes, there’s one more wildcard: utility-scale solar development projects are being upended as the Commerce Department sorts through a complaint lodged in February by a domestic manufacturer that Chinese companies are dumping solar modules. Postponed and even scrapped projects may not have an impact this year, but may well affect supply adequacy in 2023.

This post appeared first on Power Engineering.