Following successful permitting, the company plans to build a two-unit, 1,200 MW combined cycle plant in Monroe County. The facility would be on land already owned by Oglethorpe Power and adjacent to the Smarr Energy Facility, another gas-fired plant. Oglethorpe claimed the new addition would be the “highest-performing, lowest-emitting and most efficient natural gas plants in the state.” Total capital investment would be approximately $2 billion, the company reported.

In Talbot County, Oglethorpe would also build a simple-cycle combustion turbine unit at an existing plant. This new approximately 240 MW peaking unit, which would be the seventh at the Talbot Energy Facility, would have dual-fuel capability. The development of this new unit would represent a capital investment of approximately $360 million.

More details on the projects’ construction and timelines would be available after permits are received, Oglethorpe said.

Oglethorpe Power continues activity in Georgia, where it recently acquired Walton County Power, a 465 MW, three-unit combustion turbine generation facility in the city of Monroe. The facility was purchased from Mackinaw Power Holdings, an affiliate of the global investment firm, The Carlyle Group. Financial terms of the transaction were not disclosed.

U.S. natural gas-fired power generation is expected to grow faster than it has in years. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

Following approval, NRG would begin construction on two of the three facilities as early as October of this year.

This first application is for a new 721 MW natural gas combined-cycle unit at NRG’s Cedar Bayou plant in Baytown, Texas. In the coming weeks, the company plans to submit applications for two quick-start natural gas peaking projects near Houston: the 455 MW project at TH Wharton and the 456 MW unit at Greens Bayou.

NRG anticipates that these three projects will be capable of supplying power to customers in under 30 minutes. Completion of these projects is contingent upon timely loan approvals from the PUCT and tax abatements by local authorities.

“Texas is projected to have the fastest growing electricity sector of any market in the United States,” said Larry Coben, NRG Chair, Interim President and CEO. “The state expects electricity consumption to grow by 65 gigawatts, or nearly 77% through 2030. NRG urges advancement of any truly shovel-ready projects to meet the demands of the state’s growing and electrified economy. Our three shovel-ready projects have been in development for five years and are among the select few projects positioned to bring much needed flexible and dispatchable generation to the state this decade.”

Facilitated by Sugar Land Economic Development and Tourism (SLOEDT), the development will be located within an approximate 100-acre mixed-use business park at 1 Circle Drive, with direct proximity to Highway 6 and Highway 90A.

“We must take action now to prevent the kind of devastating impacts we’ve seen from various weather disasters, one example being Winter Storm Uri in 2021,” said Sugar Land Mayor Joe Zimmerman. “We are committed to building a resilient and dependable power infrastructure here in Sugar Land. This initiative not only ensures a critical resource for our community, but it will also make it easier for us to attract premier business partners, fostering long-term economic growth.”

Once completed, the plant would provide power to the Texas grid. In the event of a grid failure, weather-resistant engines would be able to restore power within five minutes. The plant will provide electricity without relying on external grids, even during a complete blackout.

“We plan to construct the plant with highly efficient engines that are capable of producing power independently, even during extremely low or high temperatures,” said SLOEDT Assistant Director Alba Penate-Johnson. “These aspects align with the Electric Reliability Council of Texas goals (ERCOT), which operates Texas’s electrical grid.”

Currently, project leaders are selecting development partners who will enter into a long-term ground lease agreement once the deal is facilitated. Construction partners and land use permits are also being announced later this year.

On Tuesday May 21, The A&M System asked private developers to submit their proposals for building gas-fired peakers on A&M System-owned property with financing through the newly-created $5 billion Texas Energy Fund.

The A&M System laid out around 30 potential sites where peaker plants could likely be built, and although it would prefer sites close to its campuses, the Public Utility Commission of Texas will have the final say, the Texas Tribune reports.

“This will help ensure our campuses and their local communities never go dark again, while adding power to help ensure all of Texas is protected,” said John Sharp, Chancellor of The Texas A&M University System.

The Texas Energy Fund was created by Senate Bill 2627 in 2023, spurred by Winter Storm Uri in 2021, and voters approved the constitutional amendment creating the Texas energy fund in November 2023.

Duke Energy is already under fire in North Carolina for its plan to blow off a state deadline to curb carbon pollution while also building a massive new fleet of fossil fuel plants.

Now, the company’s blueprint is locked on a collision course with fresh rules from the Biden administration, which target coal and new natural gas plants and take effect in eight years.  

“Duke is going to have to go back to the drawing board,” said David Neal, senior attorney with the Southern Environmental Law Center, “and come up with an alternative that is compliant with the rules.” 

While much focus on the long-awaited Biden rules has centered on coal, their impact on natural gas is arguably more significant. Duke isn’t alone among American utilities in being forced to re-examine long-term generation plans as a result. 

“We think it’s important for every utility and every commission to take a step back,” said Amanda Levin, director of policy analysis with the Natural Resources Defense Council. 

But even as the federal regulations underscore a law unique to the state, it’s not clear if North Carolina regulators will take a beat – or even if there’s time for them to corral Duke and an array of stakeholders to rework, vet, and approve a new carbon reduction and long-range plan due by the end of the year. That’s why many advocates say debate over the utility’s immediate next steps will be crucial. 

“It’s going to be important to adopt a near-term action plan that really is ‘least regrets,’” said Neal, who’s representing numerous clean energy groups in the proceeding on Duke’s generation plans. “The new rules just put further emphasis on what we already knew was true: we’re going to have to accelerate the adoption of clean resources.”

‘Not… achievable on the timelines presented…’

Duke’s existing fleet of natural gas-fired plants aren’t affected by the new Biden rules. Nor are the smaller gas plants Duke proposes to occasionally satisfy peak demand and serve other limited roles on the electric grid.

But the company plans at least five large, combined-cycle plants in the Carolinas that are impacted by the rules. The four projected for North Carolina include a 1,360-megawatt plant in Roxboro, about an hour north of Durham, for which state regulators are now weighing a permit application.

Natural gas is a fossil fuel, but Duke deems the Roxboro plant and others like it essential to the zero-carbon electricity future that state law mandates by 2050. These baseload generators can back up sources like wind and solar to ensure reliability. At the point of combustion, they produce about half the carbon pollution of coal. And in theory, hydrogen molecules separated from chemical compounds could ultimately supplant gas as a fuel, bringing the plants’ carbon emissions down to almost nothing. 

“Natural gas is available 24/7 — with fewer emissions than coal and at a lower cost than renewables alone,” Duke said on its website this year, around the time it asked regulators for permission to build the Roxboro plant. “The new [Roxboro] units would be designed to operate on carbon-free hydrogen in the future.”

But critics say this rationale is flawed in virtually every respect. The cost of natural gas is on the rise, and one recent study showed it was a major driver of recent Duke rate hikes in parts of North Carolina. In December 2022 during Winter Storm Elliott, gas plants failed when they were needed most — in the wee, frigid hours before the sun rose — helping to cause rolling blackouts that impacted half a million customers in the state. Drilling and transporting gas leaks methane, a greenhouse gas 80 times more powerful than carbon, nearly canceling out reduced carbon pollution from smokestacks.

As for hydrogen, experts believe it can serve a small role in a zero-carbon economy — but mostly not in the power sector. Even if it’s carbon-free when burned, hydrogen made from fossil fuels is hardly nonpolluting and also inefficient. Hydrogen fuel produced from renewables should be reserved for limited applications, they say, such as long-distance aviation fuel or to power the few gas plants still running in the middle of the century. 

“In our modeling,” said Levin, “hydrogen in the power sector is used just for that last 5% of the decarbonization of the entire grid.” 

Still, the power plant rules promulgated by Biden’s Environmental Protection Agency don’t wrestle with reliability, ratepayer impacts or even methane leakage. They cover carbon dioxide pollution alone, and they’re designed to reduce what’s emitted from the smokestack by 90% beginning in 2032. 

That limit is based on carbon capture — in which carbon dioxide is sequestered underground rather than released into the atmosphere — a technology widely viewed as infeasible in North Carolina because of its geology. And while other techniques that would achieve the same pollution cuts are allowed under the federal rules, none are yet ripe. 

One candidate is now being developed at utility scale in Texas but won’t be deployed until at least three years from now. As for hydrogen, it would have to fuel 96% of Duke’s new baseload gas plants beginning in 2032 to meet the emissions limit — an impossible feat according to the company’s own communications with regulators.

Duke’s current forecast shows its gas fleet running on about 3% hydrogen beginning in 2041, then “holding steady until significantly more hydrogen is required to meet carbon-neutral by 2050,” to comply with state law. And in a brief discussion of the impending federal power plant rules in its August draft of its long-term plan, Duke noted: 

“Hydrogen is an important and potentially transformational fuel for the future of the resource portfolio, [but] the volumes necessary to utilize the hydrogen compliance pathway are not thought to be achievable on the timelines presented.” 

‘It’s a pretty huge gap’

Thus, if regulators allow Duke to build large new baseload gas plants, the company can only run them 40% of the time or less, beginning in 2032 and until technology becomes viable to slash their emissions.

The Roxboro plant, which Duke plans to put into service at the beginning of 2029, would operate at its planned capacity for just three years in that case. Afterwards, its vaunted ability to provide around-the-clock electricity would be severely curtailed. 

Multiply the Roxboro conundrum by five, and the mismatch between the Biden rules and Duke’s gas ambitions becomes clear. 

In its August discussion of the expected Biden rules, Duke said it considered running its new combined-cycle baseload plants at 50%. Making up for the resulting difference between demand and supply, including building another large gas plant that would run at half-speed, would require an extra $3.6 billion, the company estimated.

Tyler Norris, a former vice president at Cypress Creek Renewables and a PhD candidate at Duke University, estimates that if the 6,800 megawatts of baseload gas plants Duke announced in January were planned to run at 75% and had to ratchet down to 40% operations, the difference would be greater still. Filling it only with solar could require 9,500 megawatts of capacity in a single year — nearly double what’s online in Duke’s territory today. 

“That’s probably on the high end,” said Norris, but, “it’s a pretty huge gap. Something’s going to have to change in the plan.”

Then, there’s the question of whether it makes sense for ratepayers to pay to fill that gap, especially if they’re also shelling out full price for underutilized plants. 

“We’re all paying for these plants that admittedly have to sit idle more than half of the time?” asked Dave Rogers, deputy director for the Sierra Club’s Beyond Coal campaign. “Should customers really be forced to pay for those?”

Adhering to the Biden rules on coal plants appears more straightforward.  

Duke must shut down its entire coal fleet by the start of 2039, and any plants still running in 2032 must be fired partially with gas. The utility already plans to meet that deadline for eight of its 12 remaining coal smokestacks, covering six sites. Two outliers in Belews Creek, just outside Winston-Salem, can already be fueled with gas. That leaves two units in Roxboro, about an hour north of Durham, that the utility now plans to keep online until 2034.

“The logical thing is to retire that coal plant at least a couple of years earlier. Whatever replaces it will be lower cost,” said Rogers. “That’s the big thing in front of the commission as it pertains to the [coal plant] rules.”

Timing also looms large. State law requires Duke to curb carbon emissions 70% by 2030, with two years’ wiggle room. If regulators authorize a nuclear or wind project that causes logistical delays beyond Duke’s control, the postponement could be indefinite. The company now hopes to exploit the latter loophole, with its preferred path to net zero achieving the 70% benchmark by 2035 or even 2037. 

With their deadline of 2032, however, the Biden rules help bolster the case for Duke to rein in its carbon emissions sooner. Doing so wouldn’t just make it easier for the utility to meet the ultimate goal of near-zero emissions by midcentury. It would also significantly reduce overall carbon levels in the atmosphere. 

“The thing about climate is it’s not just about achieving net zero in one year and one year only,” said Levin. “Climate is a cumulative emissions problem. If you’re doing status quo until the year you’ve made a net zero commitment, you’re not consistent with a 1.5 or 2 degree warming trajectory.”

No change to the ‘path forward’? 

Still, while advocates have long pressed Duke to build more battery storage, solar, and wind in place of gas and coal, making the switch in the complex utility modeling tools is no simple task, with a host of variables involved — from transmission capacity to reliability to siting.  

“Duke has already submitted its modeling twice now. I doubt that either North or South Carolina commissions will want to do another round of that at this point,” said Maggie Shober, research director for the Southern Alliance for Clean Energy, on a recent webinar about the Biden rules. But, she added, “this will absolutely come up in the process before the [North Carolina Utilities] commission.”

For its part, Duke hasn’t indicated any plans to re-do its projections.  

“While we are analyzing the final rules, our view is that [they do] not change our path forward in North Carolina as we continue retiring our coal plants and supporting the state’s unprecedented growth with an all-of-the-above approach that’s designed to deliver affordability and reliability for customers,” company spokesperson Bill Norton said in an email. “Natural gas remains an essential resource in this diverse mix that can be dispatched to meet demand 24/7.”

If that position holds, and state regulators don’t seek to change it, it raises the stakes considerably for the “near-term action plan” expected as part of the plan due by the end of the year, as well as the permit application pending right now for the Roxboro plant.

That short-term plan, said advocates, shouldn’t just account for the risk of new gas resources and the timing of coal retirements, but also allow for more renewables by removing the annual connection caps Duke proposes for both battery and solar.

“I think this is an excellent opportunity,” said Norris, “to revisit the potential to achieve a higher interconnection rate for zero-carbon resources.”

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

Proposals must be submitted by June 21, 2024 and must be for 50 MW to 500 MW for various periods through December 2029. TVA is seeking “Firm Generation Resources” or “Firm System Commitments” as defined in its RFP. Proposals should complement TVA’s existing generation resources and be delivered to the TVA service area, TVA said.

TVA recently received attention for moving ahead with a plan for a new natural gas plant in Tennessee despite warnings that its environmental review of the project doesn’t comply with federal law. The utility announced in April that it would replace the aging coal-burning Kingston Fossil Plant with gas amid growing calls for the agency’s new board of directors to invest in renewables.

Decommissioning the Kingston plant, the site of a massive 2008 coal ash spill, is part of TVA’s overall plan to reduce its reliance on coal. In analyzing alternatives to replace the plant, the utility considered either a new 1,500-MW gas plant or 1,500 MW of solar combined with 2,200 MW of battery storage. TVA concluded that a 2027 deadline for retiring the current plant does not give it enough time to develop the renewables alternative.

This article includes reporting from the Associated Press.

“To keep the Texas economy moving, we need more affordable, reliable power, and that’s why plants like these here in Central Texas are so incredibly important,” said Gov. Greg Abbott, who attended a ceremonial groundbreaking at the plant site near Maxwell Tuesday. “When grid demand is at its peak, these plants will quickly provide power for the grid even as we set new demand records for power every single summer.”

During the ceremony, LCRA General Manager Phil Wilson announced the new natural-gas fired plant will be named the Timmerman Power Plant, after longtime LCRA Board Chair Tim Timmerman of Austin, who has been on the LCRA Board of Directors since 2008 and has been Board chair since 2011. Timmerman is an Austin real estate investor/developer.

Each of the units can supply up to 190 MW of dispatchable power to the grid. When operating at full capacity, the Timmerman Power Plant will be able to supply enough electricity to power more than 100,000 homes during periods of peak demand.

The new unit will be built on the same 51-acre site near Maxwell in Caldwell County where construction on the first unit of a new LCRA peaker plant is underway. LCRA initially announced the construction of the plant early last year.

“We’re not just talking about the need for more power, we’re doubling down on helping meet the need,” said Phil Wilson, LCRA general manager. “We are proud to be building two units at once to help support our rapidly growing state.”

The new peaker unit will be nearly identical to the one already under construction, which is scheduled to be in service in 2025. Construction will begin later this spring on the second unit, which is expected to be in service in 2026. A peaker plant is one that typically is used for brief periods during times when the demand for power approaches or surpasses the amount of available power.

Each unit will be powered by 10 Wärtsilä reciprocating engines. Minnesota-based Fagen, Inc., will be the Engineering, Procurement and Construction contractor for both units.

The new plant will be the second peaker plant in LCRA’s generation fleet. LCRA also owns and operates Winchester Power Park, a 184-MW natural-gas fired peaker plant in Fayette County.

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.