Challenges to add renewables to the mix of power supply add to issues that will keep natural gas generation growing and an important part of the energy stack in 2024.
“Coal and natural gas remain important to the U.S. electric grid, even as variable renewable resources such as solar and wind grow,” U.S. Energy Information Administration (EIA) Administrator Joe DeCarolis said in the agency’s January Short-Term Energy Outlook.
According to EIA, overall demand for natural gas increased by 3% in 2023 compared with 2022. While residential and commercial sector consumption faltered, LNG and Mexico gas pipeline exports, as well as an uptick in electricity generation use, supported the uptick.
The International Energy Agency (IEA) said in December that in late August, for the very first time, the United States met more than one-half of its electricity demand from natural gas, “encapsulating a summer during which gas-fired electricity generation grew dramatically.”
The global energy watchdog said, “In just the past two years, natural gas’ share of the U.S. power mix rose from 40% to 45% for the summer months of July and August.” The Paris-based agency attributed the gains to a confluence of factors, including a significant drop in the price of natural gas, coal plant retirements, low output from wind and hydropower, and high cooling demand in some regions.
The IEA said the record share of natural gas in the power mix would likely continue through 2024. EIA, however, noted renewable power sources would eat into the gas share of the energy stack.
The EIA said 36 GW of solar capacity is scheduled to come online in 2024 and 43 GW in 2025 in the United States. In addition, 30 billion kWh of wind generation could be added in 2024, and another 17 billion kWh may come online in 2025.
However, challenges to building and bringing renewable energy onto the electric grid keep natural gas an important source for power generation, industry experts said.
The Renewable Challenge
It hasn’t been an easy road for the wind industry in the United States. Many utilities sold off commercial wind farms. Developers also have canceled several wind projects along the East Coast recently, considering them no longer financially feasible. And challenges are ahead in 2024.
For example, as the new year began, Equinor ASA and BP plc announced a “reset” for their joint venture Empire Wind 2, a 1,260-MW offshore wind project off the coast of New York, citing changed economic circumstances.
The project was not canceled. However, continuing the development and participating in a future offshore wind solicitation may take longer.
The possibility of more project delays or cancellations of renewable projects poses a risk for power generators. They are hedging against those risks by adding additional natural gas capacity.
Gas Capacity Growth
According to EIA, 20 natural gas power plants are expected to come online by 2025 with a total capacity of 7.7 GW. About 2.8 GW of simple-cycle gas turbine units would be sited in Texas near high population areas.
Texas, which leads the country in wind power generation, needs more fast-starting generating capacity to cope with rising power demand and greater variability in supply, according to EIA.
A majority of Texas residents agree. In November, Texans resoundingly approved Proposition 7, a constitutional amendment to create the Texas Energy Fund. With its passage, the Public Utilities Commission of Texas (PUCT) would have the authority to issue low interest loans to power plant operators seeking to add generation capacity.
The amendment did not explicitly limit eligible projects to natural gas-fired generation, but only dispatchable projects of at least 100 MW would qualify for a loan.
The Electric Reliability Council of Texas (ERCOT) and PUCT have become increasingly concerned with reliability.
Rice University’s Ken Medlock, senior director for the Baker Institute’s Energy Studies Center, told NGI then that Proposition 7 and state Senate Bill 2627 resulted from those concerns. “Reliability is the issue, so sufficient dispatchable capacity is important. You can liken this to an insurance policy” for the electric grid, he said.
Utilities' choice to add natural gas capacity is predominantly because power generators need help smoothing the intermittent nature of the solar and wind supply.
Reliable Natural Gas
While utilities are planning to add battery storage additions of 14 GW (80%) in 2024 and 9 GW (29%) in 2025 to smooth the shifting nature of renewable generation, natural gas should continue to benefit to help balance the supply, said EIA analyst Steve Harvey. He discussed the benefits in a recent discussion on the online energy platform Enelyst.
According to the conservative think tank Cato Institute, “variable renewable energy sources like wind and solar are resource-constrained and dependent on such factors as weather and the time of day, generating power only 25% to 34% of the year.”
Mobius Energy analyst Zane Curry agreed. “Renewable power supply is a factor of weather,” he told NGI.
“The pattern of renewables is that peak renewable output is typically during annual low points of demand,” Curry said. “Solar depends inherently on how sunny it is,” and “while you would love to have wind in July, wind is almost always strongest in spring and fall when power load is lowest.”
“What happens when the wind isn’t blowing and the sun isn’t shining?” Curry asked.
Echoing the sentiment was director Jacqueline Cochran of the Grid Planning and Analysis Center of the federal government’s National Renewable Energy Laboratory. During a recent interview on National Public Radio, Cochran said, “What a utility never wants to do is be out of power.”
She added, “We have a mismatch in when renewable energy is generated versus when there’s a demand for electricity.”
Conversely, dispatchable power sources, like natural gas, produce electricity on demand.
“This allows operators to vary dispatchable energy sources based on the needs of the grid, while variable renewable energy varies depending on the weather, season, and clock,” according to the Cato researchers.
Curry said without access to renewables, nuclear power can be maxed out, and as more coal generation is retired, the more utilities will depend on natural gas for a reliable power supply.
Efficiencies And Costs
Industry experts said other significant factors, including cost and efficiency, would also contribute to the staying power of natural gas.
Curry said the annual capacity factor for renewable energy is about 40%. And, although coal may be less expensive on an energy basis, Harvey said from 2024 through most of 2025, coal could be more expensive when accounting for the higher thermal efficiency of natural gas.
“New, efficient combined-cycle gas turbine plants currently entering service use about 65% of the primary energy input of a coal-fired plant to provide the same generation,” Harvey said.
EIA also expects natural gas to be competitively priced, with the Henry Hub spot price averaging $2.60-2.70 in 2024, an increase of about 10 cents from 2023. In 2025, forecasters see gas averaging $2.90 as LNG exports increase.
Despite the overall lower price for natural gas, limited transportation capacity increased price volatility in 2023, particularly in the Northeast, Midwest and Southeast. The price volatility is expected to continue.
Transportation Troubles
Price instability was reflected in NGI’s January Bidweek as the National Avg., based on trades in late December, fell 25.0 cents month/month to $3.075. That was also well below the year-earlier average of $13.720 for January 2023 Bidweek. But prices jumped in the Northeast, Appalachia and Southeast, which had turned substantially colder in the last weeks of 2023 and remained that way to start the New Year.
“The Northeast region has experienced periods of high gas and power spot market price volatility over several recent winters, including the recent winter of 2022/23,” said the Northeast Gas Association.
Natural gas prices in the United States tend to spike in winter months. The problem can be particularly extreme in New England.
“The New England region has limited natural gas pipeline capacity available for electric generation during cold periods,” ISO New England Inc. (ISO-NE) spokesperson Mary Mannion told NGI. “Greater demand for natural gas can result in higher costs.”
Mannion said the region’s natural gas generators may turn to LNG to meet their needs.
However, New England could lose one LNG source if Constellation Energy Corp. were to shut down the Everett LNG import terminal in Maryland. In May the Mystic Generating Facility, the terminal’s primary customer, is to be retired.
Mannion said an analysis by ISO-NE for winter 2024-2025 power system operations (which would be the first winter following the retirement of Mystic) suggested that the region’s electricity system could withstand the retirement of Everett.
Still, “the ISO believes that it would be prudent for the region to retain its limited gas infrastructure, including Everett, in the mid-term,” Mannion said.
New England isn’t alone. “Every region has already seen elevated volatility,” Curry told NGI.
