U.S. natural gas-fired power generation has gotten a demand boost from coal retirements over the past year, but those tailwinds are set to fade in the coming months as a wave of new renewables competes for share of the power stack.
Natural gas has gained about 1.7 Bcf/d of power generation demand since mid-2023 as retirements and competitive gas prices have made coal less competitive, according to Enverus senior energy transition analyst Carson Kearl.
Those gains have been shown to be “relatively sticky” thus far in 2024, Kearl told NGI. However, additional increases aren’t likely after favorable year/year comparisons run out in June and July and “additional renewable capacity starts to eat away at that bump in gas demand we saw last year,” he said.
Enverus expects natural gas-fired generation to dip in the back half of the year so that 2024 is relatively flat to 2023 levels, Kearl said. That view of flattening load growth for gas generation is generally shared among analysts if a normal season plays out.
However, a hotter-than-normal summer – as has been forecast – would boost gas demand projections. It’s a scenario that has played out in recent years, with warnings about natural gas demand being pinched by renewables ultimately not panning out because of hotter weather, among other factors.
Solar Surge
This year, additional solar capacity will be added to the mix. The U.S. Energy Information Administration (EIA) has forecast 36 GW of solar capacity and 7 GW for wind being added to the grid in 2024. Those additions would increase their combined capacity to 281 GW.
Around 14 GW of renewable capacity has come online this year, with another 16 GW of utility scale capacity and 10 GW of residential solar still to come, according to Kearl. Because of the intermittency, that works out to around 10 GW of generation from the 40 GW of installed capacity, he said.
LSEG senior market analyst Chad Bircher said the solar additions loom larger than wind. More than half of this year’s new solar additions are to be in Texas, California and Florida, he said.
“Coal-to-gas switching is largely a completed story, and for those states at least, it is now a story of gas-to-solar switching,” according to Bircher.
The growth in solar is evident in Wood Mackenzie’s forecast for U.S. summer generation demand. The firm expects nuclear and renewable generation gains to slightly outpace a 1% increase in total load growth. This would lead to gas burns being roughly flat to slightly down compared to last year, analyst Eric McGuire said in a recent webinar.
The firm estimated that natural gas generation could fall by 1% year/year this summer, with solar generation increasing 22% and wind up 10%.
EIA recently said it expects U.S. gas power burn to remain flat from June through August and average at 44.7 Bcf/d to match the year-earlier record. The Federal Energy Regulatory Commission also is predicting domestic gas power burn to hold steady this summer.
Paths To Growth
Weather, as always, remains a wildcard.
East Daley Analytics has a base case calling for an increase of 0.1 Bcf/d for the summer gas power burn from April to October. Analyst Jack Weixel said there could be as much upside as 0.3 Bcf/d of additional burn over the previous year.
“We believe that we’re going to set a record this summer at about 38.4 Bcf/d,” Weixel said on a recent webinar. Together with the slight power generation gain, an increase of 1.3 Bcf/d for residential and commercial demand and 0.5 Bcf/d growth from industrial users increases total gas demand for the April-October period by 1.9 Bcf/d, he said.
During the peak months of June through August, East Daley expects the gas power burn to average 44.6 Bcf/d, similar to last year and EIA’s forecast. “It’s definitely going to be a hot one,” Weixel told NGI.
Wood Mackenzie also has left the door open for gas-fired power demand gains this summer.
McGuire noted that U.S power load grew by 1.7% in April from a year earlier, much faster than the firm’s projected pace. This allowed gas output to grow by 1% and solar to jump by 34% year/year. Canada was the driver, he noted. In early 2024, the country flipped from a power exporter to an importer of U.S. electricity. That boosted overall growth for U.S. power demand to 3% from a year earlier, he said.
“If not for these incremental power exports, April gas burns would likely have been down year over year,” McGuire said. “This will continue to be a factor throughout the summer and is a bullish risk to our forecast.”
Other factors that could benefit gas demand are delays in completing renewable projects.
Renewable capacity additions have lagged EIA projections since 2021, particularly for solar, according to McGuire. In contrast, gas-fired unit capacity additions have exceeded EIA projections, and together with renewable delays helped drive the stronger gas burns in the summer 2023, he said.
Weixel was similarly optimistic. “I am certainly bullish on gas-fired power demand this summer,” he said. “If it is as hot as most forecasters say it is going to be, we’ll see equal to last summer’s burn level or higher.”
Summer’s Exit
How the summer ultimately plays out may put at risk the lofty supply levels that have weighed on the natural gas market since the latter part of the winter. Following the mild season and historically low drawdown in stocks, producers responded by cutting back output to stem the oversupply.
EIA-reported Lower 48 gas inventories stood at 2,795 Bcf on May 24, still a hefty 586 Bcf, or 26%, above the five-year average.
Given the uncertainty in the summer forecast, production is likely to play a key role in how much gas is injected through the summer.
Wood Mackenzie estimates that gas storage levels would end the injection season at 3,984 Bcf. “When you add it all up, we’re forecasting this summer to be approximately 1 Bcf/d tighter than last summer. Production accounts for the majority of this tightness,” McGuire said.
Similarly, East Daley is projecting that storage levels would finish the injection season at 3,767 Bcf, or 55 Bcf above the five-year average.
“With elevated summer power burn demand with the Plaquemines terminal starting to roar up, we do see a pretty big cut into the surplus so much so that that brings on additional upwards price pressure,” Weixel said.
That said, there is market speculation that EQT Corp., the largest U.S. natural gas producer, has begun adding back the 1.0 Bcf/d it curtailed this spring.
Nevertheless, the benchmark Henry Hub spot price has rallied 58% to an average $2.570/MMBtu from May 1 to June 4. NGI’s Forward Look on Wednesday showed fixed prices for Henry Hub averaging $2.631 in July and August.
