Relatively high coal stocks at U.S. power generators could indirectly influence natural gas demand this fall if gas prices rise and tilt costs more in favor of coal.
“Elevated coal stockpiles are an indirect driver of lower natural gas prices,” EBW Analytics Group senior analyst Eli Rubin wrote in a recent note. “Should bullish catalysts send natural gas higher, an oversupplied coal market could facilitate power sector gas-to-coal switching and diminish power sector gas burns.”
U.S. coal stockpiles calculated as a “days of burn” on hand remain above Covid-19 pandemic highs for higher-heat bituminous coals, Rubin said, citing U.S. Energy Information Administration (EIA) data through June.
The higher coal stocks, coupled with long-term, take-or-pay contracts, may lead to forced coal burns despite narrow spreads between coal-fired generation costs and electricity prices, he said. This was creating “a bearish cloud over electricity markets and an indirect threat for natural thisgas.”
“There’s just a lot of coal on site at power plants,” Pinebrook Energy Advisors LLC’s Blake Owen, managing partner, told NGI. Some plants, he said, would not characterize as “uneconomically burning coals, but it’s probably putting some pressure on them to clear some of these coal piles.”
Price Matchup
Lower natural gas prices this summer have boosted the fuel’s share of the thermal stack, Gelber & Associates Ryan Parsons said in early August. Gas demand could climb even higher into the fall with gas prices “too attractive,” he said.
Central Appalachian coal costs have generally held above $3/MMBtu, according to the latest EIA data through June. By comparison, baseload prices for natural gas climbed in June, with NGI’s June Bidweek National Avg. at $1.815. That national marker rose to $2.215 in July before falling back to $1.700/MMBtu in August.
Meanwhile, Henry Hub cash prices at $1.985 on Tuesday were down 29% from a summer high of $2.800 in mid-June. Prompt month gas futures fell around 30% to $2.203 over the same period.
There are other factors for gas and coal costs, including transportation rates and heat rates, or the conversion factor into $/MWh electricity costs. Gas-fired units typically have more efficient heat rates than coal plants. However, competing fuel costs are not the end-all driver for utilities.
“How much coal gets burned is no longer a simple question of where it sits in the economic dispatch order,” according to NGI’s Pat Rau, senior vice president of research & analysis. “Coal cannot and will not crowd out gas burn one-for-one.”
Rather than a burden, Rau said abundant coal stocks can be seen as sort of an insurance policy for fuel needs. “The time honored cliche among power generators is they always feel more comfortable seeing that big pile of coal.” There are other considerations such as environmental issues that “absolutely limit the amount of coal burn.”
U.S. coal stocks stood at 138 million tons at the end of May, the highest since early 2020, according to EIA. Both Owen and Rau noted a days of burn tally of coal stocks could overstate the supply pressures on generators.
Owen said the higher days of burn number, which is total coal stocks divided by consumption, could be a function of the denominator. “Overall coal consumption is just really low right now,” he said.
Likewise, Rau noted coal retirements as a driver. “Part of the reason for those elevated coal inventories is there are simply fewer operating coal fired plants to burn that excess supply these days.”
‘All Hands On Deck’
Amid the lower gas prices and hot weather, Lower 48 gas power generation burns are up 3.7% year/year this injection season, according to Wood Mackenzie data.
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Competition is less of a concern during summer heat waves, with the East enduring temperatures that have the PJM Interconnection LLC needing all of its generation capacity.
Last Tuesday and Wednesday (Aug. 26-27), PJM had “some of the highest load” for the year, Owen said. “You pretty much have an all hands on deck situation so there's not as much fuel switching.”
However, that demand is expected to drop off as weather forecasts were pointing to moderating conditions. Rubin said national cooling demand in early September could be one-half of Wednesday’s peak and cut gas power burns by 10-12 Bcf/d.
Meanwhile, renewable energy capacity additions are taking share. Much of the gains by wind and solar have come at the expense of coal, but with retirements slowing, analysts at Enverus and Wood Mackenzie have warned that renewables could look to grab share from gas generators.
With demand ebbing into the fall shoulder season, Tudor, Pickering, Holt & Co. (TPH) analysts said gas producers could curtail more output.
Renewables output was expected to continue to fluctuate. Shorter days are leading to less sunlight for solar generation. Over the next few weeks, wind generation in Texas was expected to be “quite light” and could boost natural gas usage, NatGasWeather meteorologist Rhett Milne said Thursday (Aug. 29) on online energy platform Enelyst.
