The project is aimed at improving resilience and reliability for communities and industries along the coast. Situated atop a barge across from a substation in Leeville, the power station would play a role in supporting areas like Port Fourchon, Golden Meadow, Leeville, and Grand Isle through a microgrid system.

Key components of Entergy Louisiana’s overall project would include the construction of Bayou Power Station, expansion of the Leeville substation, and transmission connections. The microgrid system would provide backup power during outages, serving a mix of residential, commercial, and industrial customers, including industries located at Port Fourchon.

Hundreds of companies use Port Fourchon, which services 95% of the Gulf of Mexico’s deepwater energy production and handles 10-15% of the nation’s domestic and foreign oil, as a base of operation. Meanwhile, the strip from Golden Meadow to Grand Isle serves as a hub for the seafood industry. There are also many companies in the area that provide manufacturing and other services to both the energy and seafood industries.

Entergy Louisiana says the addition of Bayou Power Station would complement projects that have been completed over the past few years to build resilience into the electric system near the coast. Examples of these projects include the Caminada substation, which was elevated 20 feet off the ground on a concrete platform; upgrading around seven miles of transmission lines with about 80 steel structures between Cut Off and Golden Meadow; and undergrounding around eight miles of distribution lines along Louisiana Highway 1 from Leeville to Grand Isle and taking strategic steps to fortify the overhead electric system in the area.

The Mountain Peak Power (MPP) plant will be built in Weld County, Colorado and is expected to come online in 2025. The 162 MW plant is will be operated by Kindle Energy and serve the United Power electric cooperative.

Each LM2500XPRESS power package includes an LM2500 aeroderivative gas turbine, a distributed control system (DCS) and a Dry Low Emissions (DLE) combustion system, which can reduce emissions without the use of water, a scarce resource in northeast Colorado. 

GE said the units can perform multiple daily starts and stops and start in as little as five minutes from cold iron. These units will be assembled at the company’s Gas Power Manufacturing Excellence Center in Veresegyhaz, Hungary.

In addition to the power generation equipment, GE has provided co-development funding to speed up development and construction.

Colorado has committed to reducing overall GHG emissions 50% below 2005 levels by 2030 and 90% by 2050. This includes exiting coal by 2031. As of early 2023, seven coal-fired electric power generating facilities were operating in Colorado — until one was retired and converted to natural gas. The remaining plants are scheduled to either close or be converted to natural gas to provide peaking power.

“In a region with an increasing power demand due to planned coal-fired plants retirements and increased renewable energy generation, a mix of flexible and efficient energy sources will be necessary to achieve the carbon emissions goals of Colorado, while ensuring the reliability of power supply,” said Lee Davis, CEO of Kindle Energy.

GE Vernova said the MPP plant is the company’s second dispatchable peaking project in Colorado.

Kindle Energy currently manages and operates nearly 10.2 GW of generation located in Indiana, Maryland, New Jersey and Ohio, according to the company’s website.

The New Jersey-based company is currently building a 700 MW natural gas-fired combined-cycle plant in Iberville Parish, Louisiana. The Magnolia Power Generating Station will provide electricity directly to five rural utility cooperatives across the state starting in May 2025.

The Magnolia Power Project would include a GE 7HA.03 gas turbine, a GE STF-A650 steam turbine and a triple pressure with reheat Heat Recovery Steam Generator (HRSG). The company’s Mark VIe control system would provide turbine generator control, data collection and performance visibility.

GE has also said the Magnolia plant would have the eventual ability to blend up to 50% hydrogen.

The plant, to be located on Sandow Lakes property in Lee County Texas, will be developed and owned by a company subsidiary and will operate within the Electric Reliability Council of Texas (ERCOT). Construction is expected to begin in 2025, with the plant generating power by 2028.

Sandow Lakes Energy executed an agreement with Siemens Energy to equip the plant with two SGT6-9000HL gas turbines. The company says the SGT6-9000HL features high power output, favorable fuel efficiency, and the capability to operate on hydrogen with only minor modifications to the equipment.

The Sandow Lakes property is an approximately 32,000 acre ranch in Rockdale, Texas. The property formerly included a 1.2 GW coal-fired power plant operated by Luminant, a subsidiary of Vistra Corp. The plant had two active units at the time of its retirement in 2018: Unit 4 began operation in 1981 and Unit 5 came online in 2009.

Sandow Lakes Energy said the company was “formed for the purpose of developing, operating, and investing in energy projects in Texas” to support the property and the growing electricity demand within the state.

Facing concerns about capacity shortages and blackouts, Texas lawmakers in 2023 passed bills aimed at luring developers to generate more dispatchable or “on-demand” electricity. That legislation did not extend to renewable sources.

“As Texas continues to grow, increasing the capacity and reliability of our power grid is critical. This Sandow Lakes plant will provide 1,200 megawatts of dispatchable power, providing enough electricity for hundreds of thousands of homes,” said Texas Governor Greg Abbott. 

HELENA, Mont. (AP) — Fresh off a legal victory earlier this year in a landmark climate change case, a group of young environmental activists is trying to persuade the Montana Supreme Court to stop a natural gas power plant that’s being built on the banks of the Yellowstone River.

The 16 activists said in a court brief filed Tuesday that the air quality permit for the plant near Laurel in south-central Montana should be declared invalid or at least suspended until the state’s appeal of their climate change case is decided. The brief was in support of two environmental groups that are challenging the permit.

The activists prevailed in August in their yearslong lawsuit against the state for not doing enough to protect them from climate change. They claimed severe wildfires, flooding, drought and other problems spurred by warming temperatures violated their rights under the state constitution to a clean and healthful environment.

A state policy, which the judge in the case declared unconstitutional, did not require officials to consider the effect of greenhouse gas emissions when approving fossil fuel projects.

The ruling in the first-of-its- kind trial in the U.S. added to a small number of legal decisions around the world that have established a government duty to protect citizens from climate change.

In the brief, their attorneys said the young activists have “a unique and significant interest” in making sure new fossil fuel projects like the power plant don’t proceed “given the significant harms resulting from additional (greenhouse gas) pollution in Montana.”

The state has filed a notice of appeal of the August climate ruling to the Montana Supreme Court but has not submitted its arguments in the case.

The young plaintiffs said the justices should not wait for their case to be resolved before taking action on the power plant permit. Their attorney also asked that any constitutional climate and environmental issues should be addressed through the climate lawsuit, which was heard at trial, and not the power plant permit case.

The plant is being built to provide energy during times of high demand when prices are high on the open market, NorthWestern Energy said. The company did not oppose the activists’ attorneys filing a brief in the case.

“We respect the views of other parties, however, NorthWestern Energy’s obligation is to provide reliable energy service at the most affordable rates possible for our Montana customers,” spokesperson Jo Dee Black said in a statement. “Reliable energy service, especially during the winter, is critical for our customers’ lives.”

District Court Judge Michael Moses in Billings ruled in April that the Montana Department of Environmental Quality illegally granted the permit for the Yellowstone County Generating Station in 2021 because it did not consider the effects of greenhouse gas emissions. In response, the state Legislature updated its Montana Environmental Policy Act to say the agency did not have to consider greenhouse gas emissions unless the federal government began regulating those emissions.

In June, Moses vacated his order that invalidated the air quality permit, partly in response to the new legislation. Construction on the $250 million power plant resumed.

Roger Sullivan, one of the attorneys for the young plaintiffs, said the court’s August decision was binding on the Montana Department of Environmental Quality and other agencies when considering fossil fuel-related permits.

“We are hopeful that the Court will find our amicus brief helpful,” Sullivan said.

The NCG Site is an approximately 63-acre existing parcel of federally owned property managed by TVA in Lowndes, Mississippi, located 10 miles northeast of Columbus. The site is a former CT facility, originally constructed in 1998 and operated for several years by a private company. The company dismantled the site in 2007, removing the existing six frame CTs.

The study area for the proposed action is 145 acres and includes the entire proposed combustion turbine property as well as the adjacent substation property, which remains in operation. TVA is considering constructing and operating an approximately 500-MW combustion turbine facility at the same brownfield location as the previous generating facility, which would allow TVA to utilize existing natural gas and transmission infrastructure.

TVA has issued a Notice of Intent to prepare an Environmental Assessment (EA) or Environmental Impact Statement (EIS) to address the potential environmental impacts associated with the proposed construction and operation of the plant at the NCG site. TVA is seeking comments from the public on what should be included in the environmental review for the project.

TVA anticipates that the scope of the EA or EIS will evaluate a “no action” alternative and an “action” alternative. The “no action” alternative provides a baseline for comparing against the “action” alternative. Under the “no action” alternative, TVA would not develop the TVA-owned property in Lowndes County for energy generation. The “action” alternative would evaluate the development of the New Caledonia brownfield site for construction and operation of a CT plant.

Earlier this year, the TVA proposed three generation projects, including a pumped storage hydro plant.

First, TVA said it is studying various technologies to store energy, including pumped storage hydroelectricity. TVA will need long-duration energy storage to meet energy demand as more intermittent renewable energy sources are added to the grid.

The other two projects for which TVA is seeking input are a solar and battery storage project to facilitate its goal of 10,000 MW of solar by 2035, and a 900 MW natural gas combustion turbine and 400 MW battery energy storage system.

TVA and TC Energy also recently invested $1.25 million to study carbon capture retrofits at TVA’s natural gas-fired plants in Mississippi and Kentucky.

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.

Proponents say CCS could have a huge role in reducing emissions, while opponents note the technology is far from scale and argue that focusing on it distracts from renewable energy solutions.

Northern Indiana Public Service Co. is planning to build a 400-megawatt natural gas-fired power plant that critics say is unnecessary, out of step with clean energy goals, and happening outside the usual planning process. 

In September, the utility asked the Indiana Utility Regulatory Commission for a needed certificate of public convenience and necessity to build the $643 million peaker plant on the site of the retiring R.M. Schahfer coal plant in Jasper County in central Indiana.

The utility, known as NIPSCO, says it needs the plant to provide power during times of high demand, since it will be phasing out coal by 2028 and transitioning to renewables. 

“Energy from renewable resources does not follow the load,” David Walter, NIPSCO vice president for power delivery, testified before the commission. “In order to have generation available when the load is there but sufficient energy from renewable resources is not, it is critical to have sufficient fast-starting, quick-ramping dispatchable generation,” meaning the natural gas plant.

NIPSCO also says the plant could be converted to run on natural gas blended with hydrogen — a fuel being pushed by the U.S. Department of Energy, including with the recent funding of regional hydrogen hubs. 

Groups with intervenor status — including Citizens Action Coalition and the Industrial Group of NIPSCO customers — are in the process of filing testimony about the proposed gas plant, due Dec. 12.

Just Transition Northwest Indiana legislative director Susan Thomas said the organization “is actively opposing this build-out of what will most likely be only an occasional-use facility that either prolongs the use of fossil fuels for another 50 years or will be rendered obsolete due to more stringent climate regulations in the future.”

Larger plans 

Currently, NIPSCO’s generation mix is 43% coal, 26% natural gas, 17% solar and 15% wind. In its 2018 integrated resource plan, NIPSCO proposed to close all its coal plants by 2028, and keep running its existing Sugar Creek natural gas plant. 

NIPSCO told the commission in recent testimony that by 2028, it expects to get 31% of its capacity from natural gas-fired power, 13% from wind and 55% from solar plus storage. 

NIPSCO’s 2021 integrated resource plan called for 300 MW of natural gas. In its September filing, NIPSCO said that the proposal for a 400-megawatt gas plant is based on a recent analysis including “market shifts” since 2021, like rule changes in the MISO wholesale market and passage of the Inflation Reduction Act.

“They’re backsliding off their 2018 commitment,” is how Thomas sees it.

NIPSCO had originally planned to retire two units of the Schahfer coal plant in 2023, but had to extend to 2025 because of delays in getting planned solar online, it told the commission. Two more units at Schahfer are scheduled to close by 2028, and existing gas-fired peaking units at that site are scheduled to close in 2026. NIPSCO’s Michigan City coal plant is scheduled to close by 2026. 

Citizens Action Coalition program director Ben Inskeep noted that NIPSCO has another integrated resource plan due next fall. He said that process would be the appropriate place to explore and explain the need for new gas peaker capacity, offering more chances for public scrutiny and input.

“We’ve had great dialogue with them in the [integrated resource planning] stakeholder process in the past; they’ve been receptive to feedback,” Inskeep said. “One of the sad parts about this proceeding is it’s a step backwards in the process with them; it kind of breaks trust when you have an understanding about how things will operate and you’ve been successful, and then they’ve gone outside the process to come up with a different answer.” 

Walter told the commission that NIPSCO could not wait to launch the gas plant request during the 2024 integrated resource planning process, since that would delay plant construction “until late 2027 at the earliest,” while the company said it needs the capacity by 2026. 

Complicated finances, construction concerns 

Advocates say that rather than constructing a natural gas plant to fill gaps in renewable generation, NIPSCO could buy power from the MISO wholesale market, while also reducing energy needs through demand response and energy efficiency programs. 

Inskeep said the math behind the gas plant proposal is especially tricky given that it depends on both wholesale power prices in the future, and natural gas prices, for NIPSCO to supply its own plant. Natural gas prices have been particularly volatile over time, severely impacted by things like the fracking boom and the Ukraine-Russia war. 

“They’re saying that additional capacity will give them the ability to basically buy less electricity from the MISO wholesale power market, an insurance mechanism so they’re not buying wholesale energy during the few hours of the year when the solar and wind they are building might not be operating,” Inskeep said. “Whether this resource meets the cost-benefit analysis is unclear to me. Is it really going to make the gas plant worth it, even if you don’t take into consideration the climate change and local pollution impacts?” 

Opponents are also worried that NIPSCO is for the first time proposing to construct the plant itself, hiring individual contractors rather than hiring one firm to oversee the entire process. 

“They’ve never built a plant on their own, but now they’re going to freelance this,” Thomas said. “Where will there be transparency in this process? The potential for cost overruns is rampant.” 

Under Indiana law, a company can bill ratepayers for a “construction work in progress,” long before it is “used and useful,” the usual standard for recouping cost and a profit from ratepayers. 

Kevin Blissmer, regulatory manager for NIPSCO’s parent company, testified to the commission that this arrangement actually saves ratepayers money, since they are paying costs upfront rather than later, including costs the company took on to finance its investment. Blissmer said billing ratepayers while construction is ongoing would mean a difference of $149 million in financing savings over the project’s life. 

But the Citizens Action Coalition website describes the group’s concerns with construction work in progress, saying it “converts consumers into involuntary investors, placing the burden of up front financing costs onto them. The costs end up on their bills sooner, before they ever receive electricity from the plant in question, and there is little recourse should the costs skyrocket or the project be abandoned.” 

Gas versus renewables 

In July, NIPSCO announced its first two Indiana solar farms are operating: a 265-megawatt solar farm in Jasper County, not far from the Schahfer coal plant, and a 200-megawatt array in White County. In April, NIPSCO signed a power purchase agreement with a 198-megawatt wind farm in Jasper County. 

In its September filing, NIPSCO said the gas plant meets the state 21st Century Energy Policy Development Task Force’s recommended five pillars, helping to ensure reliability and resiliency, stability, affordability, and environmental sustainability. 

But Inskeep called building the gas plant on the retiring coal plant site a “missed opportunity,” since it precludes the chance to put wind and solar on the site and utilize the existing grid interconnections, without having to go through the otherwise lengthy process to interconnect new solar and wind to MISO’s grid. 

Clean energy advocates have also asked NIPSCO to focus on reducing peak demand rather than building more generation.

“Solutions are there and available,” Thomas said. “We’re not even giving those solutions a fair chance. They should have considered energy storage, demand response or purchase from the MISO market before they did this.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

The Kentucky Public Service Commission (KPSC) order allows LG&E and KU to build an approximately 640 MW combined-cycle plant at its Mill Creek facility, add 240 MW of company-owned solar, secure power purchase agreements for nearly 650 MW of additional solar, construct 125 MW of battery storage and implement more than a dozen new energy efficiency programs.

Regulators did not approve all of the coal retirements sought by LG&E and KU, however. The 600 MW approved for retirement represent Mill Creek coal-fired Units 1 and 2, which went into service in 1972 and 1974, respectively. The state’s public service commission deferred LG&E/KU’s proposed retirement of the larger coal-fired Ghent Unit 2 and Brown Unit 3.

Electric utilities in Kentucky are now required to receive approval from state regulators if they want to retire fossil-fired generating units. The new requirement stems from a state law passed earlier in 2023.

LG&E/KU hoped to retire Mill Creek 1 by 2024, Mill Creek 2 by 2027, Ghent 2 by 2028 and Brown 3 in 2028.

LG&E/KU had argued that proposed amendments to the U. S. Environmental Protection Agency’s (EPA) Good Neighbor Plan, if enacted, would effectively require non-SCR (Selective Catalytic Reduction) equipped coal units to cease operating or operate only at very minimal levels during each year’s ozone season beginning in 2026.

Mill Creek 1, Mill Creek 2 and Ghent 2 are not currently equipped with SCR. LG&E/KU argued operating Mill Creek 1 beyond 2024 would require [Effluent Limitations Guidelines] retrofits, while operation beyond 2027 would require a cooling tower, and operation beyond 2027 in ozone season would require the addition of an SCR due to the Good Neighbor Plan.

LG&E/KU argued that it was also economical to retire Mill Creek 2 and Ghent 2 rather than equipping them with SCR or operating the plants only outside of the ozone season.

LG&E/KU proposed retiring Brown 3, citing $26 million in major maintenance required in 2027. LG&E/KU argued this work would not be cost-effective “given the overall inefficiency of the unit.”

But the commission’s decision reflected a cautious approach. KPSC said by not making so many generation decisions on a “single, contentious load forecast” it hoped to mitigate the risk of overbuilding to the detriment of customers’ rates or underbuilding to the detriment of Kentucky’s energy adequacy.

The commission argued there was not as immediate a need to take action on Ghent 2 and Brown 3, but expects the status of those units to come up again soon when LG&E/KU have a better idea of what the EPA emission rules will look like and when they will be implemented. The Good Neighbor plan is currently stayed in Kentucky while circuit judges proceed with litigation.

“The Commission believes that it would be possible for LG&E/KU to reliably serve load with Ghent 2 and Brown 3 while they wait for more certainty with respect to the Good Neighbor Plan and other environmental regulations,” the order reads.

KPSC also denied the companies’ request to build a second combined-cycle gas plant at this time, finding that construction of a second unit should be deferred to provide for an in-service date in 2030, rather than 2028 as the companies had proposed.

Retirements of Ghent Unit 2 and Brown Unit 3, as well as construction of a second combined-cycle gas plant, would require future commission approval.

PPL said the level of expected investment is consistent with the originally proposed generation replacement plan, which projected $2.1 billion of investment overall, including $1.6 billion through 2026.

The expected investment includes additional costs related to the construction of the approved combined-cycle natural gas plant and investments needed to continue to safely operate and maintain Ghent Unit 2 and Brown Unit 3 and comply with environmental regulations.

To the extent the total capacity is not met by carbon-free options, SRP said it may procure up to an additional 500 MW of carbon-free resources. Doing so would hinge on the projects being feasible and cost effective, and if SRP can accommodate the additional resources.

Projects selected through the all-source RFP process are also expected to support SRP’s 2035 Sustainability Goals by adding to new renewable resource and storage system projects SRP has under contract and expects to have online by 2025. 

These include 2,025 MW of added solar resources, 161 MW of wind energy, and more than 1,100 MW of battery storage systems. 

SRP said that this winter season it added a new utility-scale solar resource and announced two utility-scale battery storage projects slated to come online in 2024. Three solar-powered storage projects are slated to enter service this summer, including one of the largest solar-plus-storage facilities in the state, the Sonoran Energy Center.

SRP said it plans to cut its carbon dioxide emissions intensity by 65% by 2035 and by 90% by 2050 compared to 2005 levels. The utility said it plans to host a web conference for respondents on March 20, and is requesting bid proposals by April 27. A short-list selection is expected by this fall. More information is available here.

The plants are part of the utility’s Power with Purpose initiative, which is planned to add 1,200 MW of solar and natural gas generation. The natural gas generation plants will be used as needed, per market conditions (estimated to be about 15% of the time). 

Specialized large equipment movers were used for the moving effort, which took place over nine nights in September.

Loaded on a trailer, the engines measure around 248’ long by 14’ wide and 19’ tall. The trailer and engine combined will weigh in at 796,000 pounds. The engines were shipped from Italy and then by rail to Nebraska.

In late fall, two Siemens simple-cycle combustion turbines and generators will be moved to the other new natural gas generation balancing station location, in Sarpy County. Both plants are slated to be completed by 2024.

Researchers at Sandia National Laboratories said they delivered electricity to the Sandia-Kirtland Air Force Base electrical grid using the Brayton Cycle.

The Brayton Cycle uses heated supercritical carbon dioxide instead of steam to generate electricity. It’s named after 19th century engineer George Brayton, who developed the method of using hot, pressurized fluid to spin a turbine, much like a jet engine.

Supercritical carbon dioxide is a non-toxic, stable material that is under so much pressure it acts like both a liquid and a gas. This CO2, which stays within the system and is not released as a greenhouse gas, can get much hotter than steam — 1,290 degrees Fahrenheit or 700 Celsius.

Partially because of this heat, researchers said the Brayton Cycle has the potential to be much more efficient at turning heat from power plants — nuclear, natural gas or even concentrated solar — into energy than the traditional steam-based Rankine cycle.

“Because so much energy is lost turning steam back into water in the Rankine cycle, at most a third of the power in the steam can be converted into electricity,” said laboratory researchers. “In comparison, the Brayton cycle has a theoretical conversion efficiency upwards of 50 percent.”

In a simple closed-loop Brayton cycle, the supercritical CO2 is heated by a heat exchanger. Then the energy is extracted from the CO2 in a turbine. After the CO2 exits the turbine, it is cooled in a recuperator before entering a compressor. The compressor gets the supercritical CO2 up to the necessary pressure before it meets up with waste heat in the recuperator and returns to the heater to continue the cycle. The recuperator improves the overall efficiency of the system.

In the Fall of 2019, Fleming began exploring how Sandia’s closed-loop supercritical CO2 Brayton Cycle test loop could be connected to the grid.

“We’ve been striving to get here for a number of years, and to be able to demonstrate that we can connect our system through a commercial device to the grid is the first bridge to more efficient electricity generation,” said Rodney Keith, manager for the advanced concepts group working on the Brayton Cycle technology. “Maybe it’s just a pontoon bridge, but it’s definitely a bridge. It may not sound super significant, but it was quite a path to get here. Now that we can get across the river, we can get a lot more going.”

On April 12, the Sandia engineering team heated up their supercritical CO2 system to 600 degrees Fahrenheit and provided power to the grid for almost one hour, at times producing up to 10 KW, something the teams said is a significant step.

The team’s goal is to demonstrate a 1 MW supercritical CO2 Brayton cycle system by Fall 2024.

You can read more on the Sandia National Laboratories’ announcement here.