Natural gas power burns rose to record levels in July and have so far accelerated those gains in early August, defying some forecasts that growth would flatten in the second half of the year.
Lower 48 natural gas-fired electricity generation averaged 48.1 Bcf/d last month, up about 1.1 Bcf/d from July 2023, according to Wood Mackenzie data. That was slightly behind the more than the 1.3 Bcf/d growth rate for the first seven months of the year.
In July, the Midwest accounted for the biggest share of the gains in power burns, up about 0.8 Bcf/d from a year earlier. The East rose about 0.7 Bcf/d and the Mountain region was up about 0.4 Bcf/d. The renewables-heavy South Central region accounted for most of the month’s declines, off by 0.7 Bcf/d. Pacific burns were marginally lower.
Gas power burns pushed above the 50 Bcf/d level in August and hit an all-time high of 54.7 Bcf/d to start the month, according to Wood Mackenzie’s initial estimates. The first seven days of August have averaged 51.8 Bcf/d, up about 5.6 Bcf/d year/year.
While still trending higher, the growth rate for natural gas-fired generation has been slowing. Gas power burns rose by around 2.5 Bcf/d and 2.1 Bcf/d in the first seven months of 2022 and 2023, respectively, NGI senior energy analyst Josten Mavez said. That’s an average gain of 2 Bcf/d over the past three years.
“Year-over-year demand growth has been steadily declining over the first half of the year by about 0.59 Bcf/d, which could be due to more renewable power coming online,” Mavez said.
Coal power plant retirements have fed some of the growth in gas-fired generation, but that tailwind is seen fading in the second half of 2024 and could flatten gains for gas-fired generation this summer, according to analysts at Enverus and Wood Mackenzie. American Gas Association researchers said accelerating load growth could have partly contributed to those predictions falling short.
Price Competition
The increased competitiveness of natural gas following a steep drop in prices is another factor analysts have cited.
In the first seven months of the year, NGI’s Henry Hub cash price averaged $2.105/MMBtu, down about 18% from the same period last year, Mavez said.
Henry Hub cash prices averaged $1.985 on Wednesday (Aug. 7), down by around 29% from this summer’s peak of $2.800 in mid-June. Matching that drop, the New York Mercantile Exchange (Nymex) prompt month price fell over the same period by about 33% to $2.112.
“The low futures market has been keeping us at a very high percentage of the thermal stack,” Gelber & Associates analyst Ryan Parsons said on the online energy platform Enelyst. “And this has translated to a ton of volume in power demand for natural gas.”
Parsons predicted more upside for gas power burns this summer season.
“We expect demand to climb even higher, potentially exceeding 55 Bcf/d in the coming months,” he said. “Price has been too attractive.”
Gas Vs. Renewables
The weather, as well as renewables’ limited availability this summer, also have played crucial roles driving up gas demand, Parsons told NGI.
“Intense heat waves across the Southwest, Southeast and parts of the Midwest have significantly increased cooling demand, driving up natural gas consumption for power generation,” he said.
Even with renewable capacity additions this year, “their intermittent nature means they haven’t hampered natural gas demand too much. Natural gas continues to provide the necessary reliability and flexibility, particularly during periods of low solar and wind output.”
However, one weak spot for gas power burns has been the South Central region, where gas-fired generation barely grew in the first half of the year before it flipped to a decline in July.
East Daley Analytics’ Jack Weixel, senior director of Energy Analysis, told NGI that he was not entirely sold on the theory that renewables are at fault for that decline because Texas power loads disappointed in July.
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“If you look at overall Electric Reliability Council of Texas (ERCOT) load, it’s been a bit underwhelming for peak gas-fired generation to get in on the action, at least over the past three weeks,” he said in late July.
Looking Ahead
Weixel did not put the blame on summer weather for the slump in natural gas prices. Overall demand for natural gas this summer has been a mixed bag, he said.
“Power demand is healthy,” Weixel said. East Daley estimated injection season gas power burns to finish up year/year by 0.3 Bcf/d at 38.9 Bcf/d, or at the top end of the firm’s April-October forecast.
On the other hand, LNG export demand “has been a big disappointment, mostly due to frequent outages…but the bearishness I think largely lies in the storage surplus and the fact that we can’t cut that down significantly this month or next month.”
Underground stocks finished the final full week of July at 3,249 Bcf, according to U.S. Energy Information Administration data. That’s 441 Bcf above the five-year average – slimmed down from more than 600 Bcf at the start of the injection season.
The strict diet on injections could continue in August, thanks to “incredibly strong power sector demand” and record feed gas flows to liquefied natural gas terminals running 0.8 Bcf/d above any previous August, according EBW Analytics Group’s Eli Rubin, senior analyst.
NGI’s U.S. LNG Export Flow Tracker data show feed gas deliveries to export facilities have averaged above 12.8 Bcf/d this month through Wednesday.
Aiding the power gains, Rubin cited “low natural gas spot prices and coal-to-gas switching north of 5.0 Bcf/d.”
“The natural gas market may require spot prices to remain low to keep excess supply off the market and elevate demand via coal-to-gas switching,” he said.
