The refueling will result in a carbon intensity reduction of 70% by 2030 compared to 2018 levels, AES Indiana said. The coal-to-gas conversion is expected complete by the end of 2026, which would make AES Indiana the first investor-owned utility in the state to cease burning coal.

AES Indiana says converting Petersburg Units 3 & 4 aligns with its 2022 Integrated Resource Plan (IRP). In addition to repowering, the Company’s portfolio includes adding approximately 1,300 MW of wind, solar and battery storage through competitively bid projects.

Last week, AES Indiana announced it acquired the Hoosier Wind project, a 106 MW wind farm in Benton County, Indiana. Earlier this year, AES Indiana received IURC approval for a 200 MW, 4-hour standalone battery energy storage system, the largest in the MISO region.

Petersburg Units 3 and 4 each have a nameplate capacity of 690 MW and came online in 1977 and 1986, respectively. AES Indiana retired the 230 MW Petersburg Unit 1 in May 2021 and the 415 MW Petersburg Unit 2 in June 2023.

TRENTON, N.J. (AP) — New Jersey lawmakers wanted to ask voters whether to ban new fossil fuel-fired power plants.

And then they added a loophole big enough to drive a fleet of oil trucks through.

A state Senate committee on Monday advanced a bill that would authorize a public referendum on amending the state’s Constitution to ban construction of new power plants that burn natural gas or other fossil fuels.

But the measure was changed to allow the construction of such plants if they are to be primarily used as emergency backup power sources.

The so-called “peaker” plants would operate only sporadically, including in times of emergency or when the power grid is experiencing stress.

Scientists say the burning of natural gas and other fossil fuels is one of the leading causes of climate change.

Sen. Bob Smith, chairman of the environment and energy committee, began by talking about the urgent need to address climate change.

“We have just gone through the hottest year in human history,” he said. “Texas is currently burning down. Two years ago we had New Jersey citizens dying from (Tropical Storm ) Ida. We are in big, bad, serious trouble.”

But the bill was being amended to exempt backup power plants from the ban. Such proposals are among the most contentious in the state.

Among them is a backup power plant proposed for a sewage treatment facility in Newark. Nearby residents are trying to prevent the backup from being built, saying they are already overburdened by multiple sources of pollution.

Smith said utilities are still too reliant on these backup plants to suddenly ban new ones. (The original bill would not have affected existing power plants.)

“Right now all the experts I talk to say you’ve got to have a peaker,” he said. “The citizens of New Jersey will not tolerate us getting in the way of the electricity they need.”

Larry Hajna, a spokesman for the state Department of Environmental Protection, said there are 26 power plants in New Jersey that burn fossil fuels, along with two nuclear power plants. The state no longer has coal-fired power plants.

The question is being debated around the country. In 2021, Whatcom County, about 100 miles (160 kilometers) north of Seattle, changed its land use laws to prohibit the construction of new oil refineries, coal-fired power plants, and facilities that transport fossil fuels.

Numerous states have banned coal power plants, and many say they are working toward 100% clean-energy economies.

Yet there is opposition as well. At least 15% of counties in the U.S. have prohibited new utility-scale wind or solar power projects, according to USA Today.

Dave Pringle of the Empower NJ environmental group, said New Jersey’s proposed ban does not go far enough.

“The only projects this will ban will be new gas power plants of a very large nature,” he said. “Clearly, economics dictates that those will not happen.”

In October, a Maryland-based energy company dropped plans to build a second gas-fired power plant next to one it already operates in Woodbridge, New Jersey. Competitive Power Ventures said market conditions had deteriorated to the point where the project was no longer economically feasible.

Anjuli Ramos-Busot, director of the New Jersey Sierra Club, said existing peaker plants are particularly dirty, adding the ones already in existence should be sufficient for near-term future energy reliability needs.

The most hotly fought power plant proposal in the state is happening in Newark. There, the Passaic Valley Sewerage Commission wants to build a gas-fired backup power plant to avoid a repeat of what happened when Superstorm Sandy knocked out power in 2012, causing nearly a billion gallons of untreated sewage to flow into area waterways.

The state’s public transportation agency, NJ Transit, scrapped plans for a similar backup plant last month in nearby Kearny, saying resiliency improvements to the electrical gird made the project unnecessary.

Business groups said near-term energy needs require continued use of fossil fuels.

“It is short-sighted to cut out fossil fuels,” said Dennis Hart, executive director of the Chemistry Council of New Jersey. “Our nuclear plants are 60 years old; you don’t know how long they’re going to be there.”

The bill still needs multiple layers of approval before a referendum could be placed on the November general election ballot.

Smith said the measure will be further amended in coming weeks to clarify that small backup or portable generators such as those used by homeowners or small businesses during outages also would not be subject to a ban.

The testing took place this week at ESG’s 4 MW power generation site in Holyoke, Massachusetts. Using calibrated humidity sensors positioned at both the beginning and the end of the exhaust stream, ESG says the results exceeded the modeled forecast of 83% that was developed during the initial design phase of its carbon capture process.

“This will work to our benefit as we scale to meet the demands of fossil fuel consumption in small and large power facilities, and eventually the transportation industry,” said Nick Scuderi, president of ESG Clean Energy.

ESG has plans to build a second gas-fired plant in Holyoke. The 4.2 MW plant would also be powered by Caterpillar engines.

ESG Clean Energy says it plans on implementing its CO2 capture technology across all its planned facilities and has licensed the technology to a subsidiary of Camber Energy for all of Canada and multiple locations in the United States.

The company says its system treats the exhaust stream to remove the water vapor before it is treated for capturing CO2. The system consists of a ceramic membrane that has been incorporated into a mechanical cooling system.

There’s a problem with traditional carbon capture, ESG Clean Energy says: separting and capturing carbon dioxide from a mixture of nitrogen, oxygen, carbon dioxide, nitrogen oxides, carbon monoxide, and water vapor can be difficult, and while some materials have been developed that can “selectively attach or react with the CO2 while letting the other gases pass by,” the water vapor remains. Water molecules interfere with the carbon capture process, ESG Clean Energy says, citing several scientific studies showing how water negatively affects CO2 capture.

Only 5.2 GW of generation is scheduled to retire this year – a 62% decrease from last year’s 13.5 GW, and the lowest since 2008, according to EIA’s latest Preliminary Monthly Electric Generator Inventory report. Coal and natural gas account for 91% of planned capacity retirement.

Over the past two years, 22.3 GW of U.S. coal-fired generating capacity was retired, with only 2.3 GW scheduled to retire this year, accounting for 1.3% of the U.S. coal fleet in operation at the end of last year. Most of the retirements in 2024 will come from older units, with a capacity-weighted average age of 54 years, 10 years higher than the weighted average age of operating coal plants.

The largest retirements this year will be Seminole Electric Cooperative’s 626 MW Unit 1 in Florida, and Homer City Generating Station’s 626 MW Unit 1 in Pennsylvania.

However, coal retirements are expected to increase again in 2025, with operators planning to retire 10.9 GW.

For natural gas, the 2.4 GW scheduled to retire this year represents 46% of the total expected capacity retirements. The total accounts for 0.5% of operating U.S. natural gas-fired capacity, according to EIA.

A single unit will account for 60% of natural gas-fired capacity retirements this year: the final unit at the six-unit, 1,413 MW Mystic Generating Station in Massachusetts, which has been operating since the 1940s. The remaining capacity retirements will come from he Tennessee Valley Authority’s (TVA) Johnsonville station’s 16 simple-cycle combustion turbines, totaling 754 MW.

Finally, at least 450 MW of petroleum-fired capacity is planned to retire this year, with the majority coming from TVA’s Allen power plant, which is shutting down 20 combustion turbine units totaling 427 MW.

The 810 MW combined cycle gas-fired power generation facility is located in PJM Interconnection territory. The transaction is expected to close in Q2 2024, LS Power said.

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LS Power operates a more than 16,000 MW gas generation fleet that is meant to complement its multiple energy transition platforms focused on wind, hydro and solar power, as well as battery energy storage, demand response, microgrids, renewable fuels, electric transportation, and transmission infrastructure.

“In order to decarbonize the electric grid in a reliable, affordable, and responsible manner, we will need to continue utilizing efficient, flexible gas-fired generation, for which our fleet is well positioned to help accelerate the clean energy transition by managing the intermittency of renewables,” said Paul Segal, LS Power CEO. “This is particularly critical at a time when demand for electricity is growing at the fastest rate in decades – driven by electrification, the proliferation of data centers and a manufacturing renaissance, amidst a background of coal plants retiring and renewables coming online only gradually.”

LS Power’s gas generation fleet spans 12 states and consists primarily of peaking plants along with combined cycle facilities.

LS Power also manages a growing family of energy transition platforms, including:

• REV Renewables, a provider of renewable generation and energy storage
• EVgo, a fast-charging network for electric vehicles, powered by renewable energy
• CPower Energy Management, a national distributed energy resource monetization and virtual power plant provider  
• Rise Light & Power, New York City’s largest generator, and a developer of clean energy infrastructure
• Primary Renewable Fuels, a renewable natural gas development and operating platform
• Endurant Energy, a microgrid developer and provider of distributed energy infrastructure solutions
• LS Power Transmission, a private transmission owner and developer, with 780+ miles of high-voltage transmission lines operating, and 350+ miles and multiple substations under development or construction

The 766 MW plant is powered by GE’s H-class combined cycle equipment and includes the first 7HA.01 gas turbines ordered in Mexico.

The Topolobampo III power plant uses two of GE Vernova’s 7HA.01 gas turbines, a D650 steam turbine and three H53 generators. The package is aimed at helping Iberdrola improve asset visibility, reliability and availability while reducing operating and maintenance costs, GE Vernova said. The two HRSGs were supplied by CERREY, GE Vernova’s local HRSG technology licensee.

The 7HA.01 can start and provide full power in less than 10 minutes, GE said, and it has the capability to burn hydrogen when blended with natural gas.

Engineering support for the project was provided by GEIQ, GE Vernova’s engineering center in Queretaro, Mexico, where local engineers supported the commissioning of the plant, entrance into service and will provide aftermarket operations.

The Topolobampo III power plant aims to help address the growing energy demand of Mexico’s population, which according to IEA analysis, is expected to grow to more than 150 million by 2050, from nearly 127 million today.

Mexico is among the largest producers of natural gas and the country’s output increased by 18% in 2022, over 2021. At the same time Mexico’s government plans to double the current renewable capacity by 2030, which would increase solar and wind capacity from 15 GW to 40 GW. 

The combustion turbine units, totaling an additional 750 MW, are designed to reach full power within minutes when electricity demand increases. The GE 7F.05 units began commercial operation on Dec. 31, and during testing, the three units came online to full power within 11 minutes, TVA said.

The new units join three other combustion turbines that began operating in July at the Colbert site in northern Alabama. Together, the two new sites add almost 1,500 MW to the grid that didn’t exist last winter.

The new units are part of TVA’s plan to add more than 3,800 MW of generation to the grid by 2028, according to Jamie Cook, TVA’s General Manager of Major Projects.

“Many of TVA’s new CTs are replacing older, less efficient units,” said Cook. “We can also operate them when other sources of generation, like solar, aren’t available. They supplement those sources with reliable power when we need it most.”

In September 2023, TVA and TC Energy announced they were investing $1.25 million to study carbon capture retrofits at TVA’s natural gas-fired plants in Mississippi and Kentucky, implying the Ackerman plant and the Paradise plant, respectively. Both are combined-cycle facilities.

The aim is to assess the feasibility, costs, and impacts of carbon capture technology as part of TVA’s decarbonization efforts. TVA said study findings will inform future decisions regarding TVA’s generation fleet. The federal utility’s goal is to achieve net-zero emissions by 2050.

In 2020, TVA shut down the last coal-fired unit at Paradise Fossil Plant after 50 years of operation. Paradise Unit 3, located in Muhlenberg County near the Green River, began operation in 1970 with a net generating capacity of 1,080 MW. It generated enough electricity to supply more than 800,000 average homes.

TVA’s Board of Directors voted in 2019 to retire the unit. The other two coal-fired units at Paradise were retired in 2017. That generation was replaced with a combined-cycle natural gas plant with a baseload capacity of 1,025 MW, which began operation next to the fossil plant site in 2017.

Dairyland Power Cooperative, Minnesota Power, and Basin Electric Cooperative have been working to gain permission to build the $700 million power plant for more than three years. Plans call for the facility to be built near an Enbridge Energy pipeline hub on the banks of the Nemadji River, which flows into Lake Superior, in the city of Superior, Wisconsin.

Along with the gas plant, the proposal calls for a new 345-kilovolt transmission line, relocation of an existing gas pipeline, and construction of a new gas pipeline to tap an existing gas supply network. Facility construction is expected to begin in spring 2024 with a 2028 in-service date.

Earlier this year, Indigenous tribes in Michigan, Minnesota, and Wisconsin asked federal officials to deny Dairyland Power Cooperative’s request for a loan to help build a natural gas-fired power plant on the shores of Lake Superior, calling the project “unthinkable” in the face of climate change.

Chippewa tribes located across the northern third of the three states sent a letter to U.S. Department of Agriculture officials Sept. 11 asking them to deny the utility’s request for a $350 million public loan. The request was intended to cover the utility’s share of the cost of building the Nemadji Trail Energy Center power plant.

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Opponents argue that not only is the gas plant problematic in its own right, but it will also drive more investment in gas infrastructure and fracking. The utilities say using natural gas is a flexible means of producing electricity when wind and solar aren’t available and would serve as an alternative producer as utilities shut down coal-fired plants.

Dairyland says the plant could be retrofitted to run on up to 30% hydrogen, which is being promoted as an industrial energy source by the Department of Energy including with the establishment of hydrogen hubs nationwide.

The plant would be a merchant generator selling power on the open market in the MISO regional transmission organization territory.

“From filling in critical gaps when solar and wind output is low to serving as a safety-first resource
during storms and extreme temperatures, NTEC is key to sustaining grid reliability and supporting
renewable energy production,” said Dairyland Vice President of Strategic Growth John Carr

The utilities say a subsequent Supplemental Environmental Assessment (SEA) confirmed the facility will reduce greenhouse gas emissions – decreasing carbon dioxide (CO2) emissions by an average of 964,000 tons per year.

Dairyland recently submitted a Letter of Interest for funding through the U.S. Department of
Agriculture’s New Empowering Rural America (New ERA) grants program for a portfolio of clean energy projects.

“The eight solar and four wind energy resources in Wisconsin, Iowa and North Dakota proposed by Dairyland depend on NTEC for on-demand response support,” Carr said.

This article includes reporting from the Associated Press and the Energy News Network.

The CCGT capacity factor rose from 40% in 2008 to 57% in 2022. EIA said during that time, increased efficiency has improved the competitiveness of newer CCGT units against other fuel sources and older CCGT units.

The agency said two factors affect the utilization of a CCGT unit: the efficiency of the generator and the delivered cost of natural gas. More advanced H- and J-class natural gas turbine technology entered the market in the mid-2010s, increasing the efficiency of newer natural gas-fired power plants. Lower natural gas prices typically increase capacity factors at natural gas-fired power plants because the electricity generated is cheaper than from other sources, such as coal-fired plants. In 2012 and 2015, the annual average capacity factors of CCGT units increased by more than seven percentage points when the annual Henry Hub natural gas price declined.

Grid operators generally dispatch generators sequentially from lowest to highest cost. Because CCGT units built between 2010 and 2022 typically have the lowest operating costs, they are dispatched more frequently compared with older CCGT power plants.

In 2022, the capacity factor of CCGT units that began operations between 2010 and 2022 averaged 64%, compared with 55% for those that began operations between 2000 and 2009 and 35% for units that began operations between 1990 and 1999.

About one-half of today’s CCGT capacity was built between 2000 and 2006. This sudden increase in the number of CCGT plants was in response to power shortages that occurred in the late 1990s, coinciding with new and more efficient F-class natural gas turbines entering the market. Now, many of these CCGT plants are about 20 years old, which could lead to lower capacity factors as the units age.

Lower heat rates, the ratio of the amount of fuel required to generate a unit of electricity, are the result of increased efficiency of newer CCGT power plants. CCGT power plants built between 2010 and 2022 have the lowest average heat rate among all CCGT plants, at 6,960 British thermal units per kilowatt-hour (Btu/kWh) in 2022, which is 7% lower than units built between 2000 and 2009.

Combined cycle plants are already the single largest source of both electric generating capacity and electricity production in the U.S. Last year, the EIA reported that eight new natural-gas fired combined cycle plants had come online or would come online in 2022, adding 7,775 MW of generating capacity to the U.S. grid.

The commissioning of 7,775 MW of new combined cycle capacity in 2022 eclipsed the previous two years, when 5,002 MW and 3,578 MW were added in 2020 and 2021, respectively. However, gains in 2022 are lower than those recorded from 2017 through 2019.

“In response to current market conditions, Invenergy is exploring other opportunities to provide reliable energy and significant economic benefits,” a company spokesperson told Power Engineering in a statement.  

The Allegheny Energy Center, a proposed 689 MW combined-cycle plant, faced years of opposition from neighbors and environmental groups due to concerns over pollution controls. An appeal had been brought by the Environmental Integrity Project (EIP), Clean Air Council (CAC) and PennFuture challenging the legality of AEC’s air permit.

Invenergy had been trying to build the AEC plant since at least 2016. It would have consisted of a GE 7HA.02 gas turbine, heat recovery steam generator (HRSG) with supplemental duct firing and a steam turbine.

The company asked the Allegheny County Health Department to terminate the permit on Nov. 9.