An array of critics came out swinging in January when Duke Energy first filed its plans in North Carolina for one of the largest fossil fuel investments in the country.  

But as the months have dragged on in the development of the company’s biennial carbon-reduction plan, some notable detractors have relented. 

Just before expert witness testimony was set to begin in Raleigh late last month, the state-sanctioned ratepayer advocate, Public Staff, and Walmart endorsed a settlement with Duke on its blueprint, which includes building 9 gigawatts of new natural gas plants that the utility says could be converted to run on hydrogen in the future.

A few days later, the Carolinas Clean Energy Business Association, a consortium of solar and wind developers, announced it had signed on too.  

The agreement, which contains some small concessions from the utility, led to low-key hearings that ended in less than two weeks. It makes it more likely that Duke will get what it wants from regulators by year’s end, including a greenlight, if not final approval, for three large new natural gas plants in the near term.

Chris Carmody, executive director of the Carolinas Clean Energy Business Association, says the proposed compromise also helps lock in forward progress on solar energy and batteries, however incremental. 

“It’s a more aggressive solar spend. It’s a more aggressive storage spend,” he said. “Certainly, we would like to see more. But first of all, we like to see it going in the right direction.” 

Clean energy advocates believe Duke’s push for new gas plants will harm the climate, since the plants’ associated releases of planet-warming methane will cancel out any benefits of reduced carbon pollution from smokestacks. At the same time, they say the investments could become useless by midcentury or sooner, before their book life is over, saddling ratepayers with costs that bring no benefits.

“There’s not much in it for their customers except unnecessary risk, cost, and more pollution,” Will Scott, southeast climate and clean energy director for the Environmental Defense Fund, wrote in a blog last month. 

But Duke’s gas bubble has proved hard to burst. For one, the company’s predictions of massive future demand from new data centers are based in part on confidential business dealings that are challenging to rebut from the outside. 

Unlike two years ago, when Duke proposed its first carbon reduction plan, no groups produced an independent model showing how Duke could meet demand without building new gas. 

“We can talk about costs, or market conditions,” said Carmody. But, he said, “we did not do any modeling.”

Public Staff ran its own numbers and has urged more caution on new gas plants than Duke proposes. But the agency is unwavering that at least some are needed.

New Biden administration rules haven’t yet proved the death knell for gas that some expected. Duke is suing to overturn the rule, but it insists that building new plants that will run at half capacity is the most economical plan for compliance.

And even as Duke is proffering more gas, it’s also undeniably proposing more solar.

Clean energy backers still object to annual constraints on solar development the utility says are necessary. But the limits have increased from less than 1,000 megawatts per year in 2022 to over 1,300 megawatts. And the settlement would result in another 240 megawatts of solar than Duke had first proposed.

“It’s an iterative improvement,” said Carmody. 

What’s more, the settlement opens a discussion with Duke about the scores of 5-megawatt solar projects across the state whose initial contracts will soon expire. A proposal for how to refit them could come in April of next year. 

“This is a really important issue to our members,” said Carmody.  “These are projects that could be repowered. They could be upgraded with storage. They could have significantly more efficient solar technology than was on them 15 or 20 years ago.” 

Still, Carmody said his group tried to word the settlement in a way that left room for clean energy advocates to continue to advocate for less gas and steeper emissions cuts sooner — and that’s certainly their plan. 

“Three power plants that will be really expensive to build and then operate for only a few years is just a ridiculous proposal,” the settlement notwithstanding, said Maggie Shober, research director for the Southern Alliance for Clean Energy. 

“We remain hopeful that there’s a lot that the [commission] can do in this carbon plan proceeding and in their final order, to move us forward on a clean energy trajectory.”

Nick Jimenez, senior attorney for the Southern Environmental Law Center, acknowledges the settlement stacks the deck somewhat against his clients. 

“Historically, the commission approves a lot of settlements,” he said. “It likes to see parties settle, especially when Duke and the Public Staff are involved.”

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

Atura Power, a subsidiary of Ontario Power Generation, is expanding the power generation capacity at its 900 MW Napanee Generating Station in the Town of Greater Napanee, Ontario. The planned expansion has a targeted completion by 2028.

Atura Power will add an M501JAC combustion turbine from Mitsubishi Power Americas, that will operate in simple cycle and provide up to 430 MW of additional electricity. Mitsubishi Power Americas said its M501JAC is known for its operational flexibility and startup times, and can also operate as a peaker. The turbine will join two M501GAC units already operating in combined cycle at the site. This will be the fifth Mitsubishi Power M501JAC turbine in Canada.

In 2019, Ontario Power Generation acquired the Napanee Generating Station and two other gas-fired plants in a $2.8 billion deal with TC Energy (formerly known as TransCanada). The facilities included the 683 MW Halton Hills power plant, the 900 MW Napanee generating station which was nearing completion at the time, and TC Energy’s 50% interest in the 550 MW Portlands Energy Center.

The deal was subject to a number of closing conditions which included regulatory approvals and Napanee reaching commercial operations as outlined in the agreement.

Since the end of 2023, 8 Rivers and Siemens Energy have collaborated on development of direct-fired super critical CO₂ turbines across a range of applications and fuel types. 8 Rivers, a developer of decarbonization technology and projects, said the ongoing turbine development program provides line of sight to future commercial projects. 

Siemens Energy has selected the commercially available generator that will be used with the Allam-Fetvedt Cycle (AFC) turbine. Siemens Energy will also provide related equipment, services, compression and grid technologies.

However, 8 Rivers said it has completed a study with a commercial party which assessed the feasibility of a biomass fueled Allam-Fetvedt Cycle negative emissions power system (Biome). This resulted in the recent signing of an MoU with the aim of commercial deployment, the company said.

8 Rivers argues that biome as a power system allows for the generation of low-cost, reliable, negative emissions power while simultaneously generating large volumes of carbon dioxide removal (CDR).  

North Carolina-based 8 Rivers develops zero-carbon technologies such as hydrogen, carbon capture and biomass carbon removal. It jointly owns NET Power, whose Allam-Fetvedt Cycle combusts natural gas with oxygen (rather than air) to fuel a supercritical CO₂ cycle that generates electricity.

The technology reuses most of the carbon dioxide produced and captures the rest, meaning it emits virtually nothing into the atmosphere. NET Power has said its plants should cost no more to build and operate than a traditional natural gas plant.

In 2018, we reported NET Power successfully achieved first fire of its demonstration plant and test facility in La Porte, Texas. At that time, the company had targeted the global deployment of 300 MW capacity commercial-scale plants beginning as early as 2021.

The spike in natural gas-fired generation on July 9 was because of both high temperatures across most of the country and a steep drop in wind generation. According to the National Weather Service, most of the U.S. experienced temperatures well above average on July 9, 2024., with particularly high temperatures on the West Coast and East Coast.

Wind generation in the Lower 48 states totaled 0.3 million MWh on July 9, 2024, compared to the the 1.3 million MWh daily average in June 2024.

According to preliminary data from the EIA, wind power in the contiguous United States produced only 302,615 MWh on Tuesday, July 23. That’s the lowest amount since the day before, when wind power produced 335,753 MWh. Six of the 10 worst days for wind power this year have been this month (July), but previous to this week’s totals, there hadn’t been a comparably bad day since October 4, 2021.

Wind farms are on track to produce an average of just 4% of power generation this week, down from 7% last week and 12% so far in 2024, per the EIA.

A battle over the state’s energy future resumes Wednesday with utility regulators hosting a hearing on Georgia Power’s plans to significantly expand fossil fuel generation over the next several years.

The Public Service Commission has scheduled hearings starting Wednesday for Georgia Power’s application to fast track the construction of three methane gas-burning units at Coweta County’s Plant Yates in order to meet increasing demands in the next decade.

Wednesday’s hearing will feature testimony and cross-examination of Georgia Power officials, PSC staff analysts and experts representing clean energy groups. The hearing would resume on Thursday if the five member commission finds it necessary. There will be another opportunity for the company’s lawyers, environmentalists and consumer watchdogs to make their case to a PSC committee on Aug. 15, prior to the commission’s vote on the proposed Yates expansion scheduled Aug. 20.

The Plant Yates expansion was among the major changes approved in 2023 to Georgia Power’s three-year strategic plan, which was approved by the five-member commission in a 4-1 vote April 16. The utility company’s revised outlook also calls for bringing more renewable energy online with the addition of a total of 1,000 megawatts of solar capacity with battery storage by early 2027 and the extension of purchasing agreements in Florida for natural gas, and with Mississippi Power, a subsidiary of Georgia Power’s parent company Southern Co.

Yates expansion opponents argue that adding more polluting fossil fuels that will be in operation for nearly 50 years will do more long-term harm to public health and the environment than clean energy alternatives. Several environmental groups criticized the company for avoiding a competitive bidding process, which could result in ratepayers paying more for the projects to be built.

Plant Yates opened as a coal-fired electricity generating plant in 1950 and operated until five of the seven units were retired in 2015 and the other two were converted to natural gas.

Georgia Power officials have argued that the Yates gas generators project needs to be fast tracked in order to meet the growth of massive data centers that continue to proliferate, primarily around metro Atlanta. The new energy sources are being promoted as a way to keep attracting companies building state-of-the-art facilities that operate around the clock to support data storage and artificial intelligence technology.

The debate over Georgia Power’s utility rates has intensified over the last several years as customers faced hikes in electric base rates and paid for soaring fuel costs, coal ash cleanup and construction overages at Plant Vogtle. The average Georgia Power residential bill will jump a total of $44 a month over two years, including $16 to pay for spikes in methane gas and coal costs.

An expert witness for the Sierra Club and Southern Alliance for Clean Energy is urging the five PSC commissioners to delay the Yates certification until a new fuel recovery policy ensures that Georgia Power customers don’t have to pay 100% of the expansion costs.

“In order to serve the public interest, the commission is obligated to create the proper incentives so that major risks to the cost of the electricity market are optimized by the parties who have the information and power  to make those decisions,” wrote Albert Lin, a California based economic and financial consultant, in June 21 testimony.

The potential $3 billion costs to implement the three-year plan update, of which approximately half is alloted for Yates’  new units, has also raised concerns about how the burden would be split between residential and small business customers versus large commercial manufacturers.

Georgia Power officials also say the company will not seek to recover from its customers any construction costs overruns, unless it’s caused by events beyond the company’s reasonable control, such as natural disasters. The terms of  the revised resource plan stem from a stipulated agreement between Georgia Power, PSC staff, and various organizations such as consumer watchdog Georgia Watch, MARTA, the Georgia Association of Manufacturers and the Southern Renewable Energy Association.

Throughout the IRP update process, the PSC members have acknowledged that the Yates expansion would play a crucial role in meeting the energy demand to support Georgia’s “extraordinary growth”, according to Jeffrey Grubb, director of resource and planning for Georgia Power, and Michael Bush, director of generation development for Southern Co.

“The expedited certification of Yates 8-10 (units) is a necessary part of the company’s commitment to continue serving our customers reliably and cannot be delayed,” their July 10 rebuttal testimony says.

Georgia Recorder is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Georgia Recorder maintains editorial independence. Contact Editor John McCosh for questions: info@georgiarecorder.com. Follow Georgia Recorder on Facebook and X.

I&M submitted the following plans to the Michigan Public Service Commission (MPSC):

• Elkhart County: Solar, 100 MW
• Hoosier Line: Solar, 180 MW
• Meadow Lake: Wind, 100 MW
• Lawrenceburg: Natural Gas. 143 MW

Lawrenceburg will serve as a capacity-only agreement, which enables I&M to buy capacity and not the energy produced. 143 MW represents a Michigan-specific contract value. Plans for these projects were also submitted by I&M to the Indiana Utility Regulatory Commission (IURC) in June 2024.

I&M will purchase the power generated from the independently operated wind and solar power plants. Both solar generation plants will be built by private developers.

Previously announced in 2022, the Elkhart County Solar Plant details have been updated for the 2024 filing. Plans before the MPSC would also provide I&M the ability to include 143 MW of generation capacity from an existing natural gas facility in Dearborn County, near Lawrenceburg, Ind.

“I&M is committed to fully supplying the energy needs of our customers now and into the future,” said Steve Baker, I&M president and chief operating officer. “Our goal is to develop and reliably operate a robust energy portfolio, with a focus on resource adequacy, affordability and environmental sustainability.”

I&M said it is in the process of a “major” generation transformation. If approved, these resources would complement I&M’s current clean-energy generation, which includes five solar power plants; wind power from four plants; six hydro-electric plants; and the Cook Nuclear Plant. I&M also continues the development of two additional solar facilities, totaling 469 MW, previously approved by both the IURC and MPSC. I&M’s coal-fueled plant in Rockport, Ind., will be fully retired in 2028. More than 85% of energy I&M generated in 2023 was carbon-emission free.

Walton County Power began commercial operation in 2001, and Oglethorpe Power said it will become one of its most efficient peaking plants, specifically utilized in times of high electricity demand. The plant’s technology features a low heat rate, enabling the plant to generate electricity using less fuel compared to other technologies. Cogentrix will operate the facility until fall 2024, when Oglethorpe Power will assume operations responsibilities. Financial terms of the transaction were not disclosed.

“As electricity demand continues to grow in Georgia, the advanced technology at Walton County Power will help ensure that we can reliably and affordably meet the increasing power supply needs of our members,” said Oglethorpe Power President & CEO Mike Smith.

Over the years, Oglethorpe Power has made strategic shifts in its generation portfolio, including the increase of natural gas, as well as its investment in nuclear energy with the recent completion of the Vogtle expansion project. The acquisition of Walton County Power marks Oglethorpe Power’s eighth acquisition of natural gas-fired generation in Georgia over the last 15 years, totaling more than 3,600 MW.

In addition to acquiring Walton County Power, Oglethorpe Power also owns and operates the Doyle Energy Facility in Walton County, a 273 MW five-unit combustion turbine plant.

“At Oglethorpe Power, we are committed to being a good neighbor in the communities where we own and operate assets. We are proud to have been an engaged corporate citizen in Walton County for many years, and we look forward to building upon our community partnership with the addition of Walton County Power,” Smith said.

WASHINGTON (AP) — The Environmental Protection Agency will not be able to enforce a key rule limiting air pollution in nearly a dozen states while separate legal challenges proceed around the country, under a Supreme Court decision Thursday.

The EPA’s “good neighbor” rule is intended to restrict smokestack emissions from power plants and other industrial sources that burden downwind areas with smog-causing pollution.

Three energy-producing states — Ohio, Indiana and West Virginia — challenged the rule, along with the steel industry and other groups, calling it costly and ineffective.

The Supreme Court put the rule on hold while legal challenges continue, the conservative-led court’s latest blow to federal regulations.

The high court, with a 6-3 conservative majority, has increasingly reined in the powers of federal agencies, including the EPA, in recent years. The justices have restricted EPA’s authority to fight air and water pollution, including a landmark 2022 ruling that limited EPA’s authority to regulate carbon dioxide emissions from power plants that contribute to global warming.

The court is also weighing whether to overturn its 40-year-old Chevron decision, which has been the basis for upholding a wide range of regulations on public health, workplace safety and consumer protections.

A look at the good neighbor rule and the implications of the court decision.

What is the ‘good neighbor’ rule?

The EPA adopted the rule as a way to protect downwind states that receive unwanted air pollution from other states. Besides the potential health impacts from out-of-state pollution, many states face their own federal deadlines to ensure clean air.

States such as Wisconsin, New York and Connecticut said they struggle to meet federal standards and reduce harmful levels of ozone because of pollution from out-of-state power plants, cement kilns and natural gas pipelines that drift across their borders.

Ground-level ozone, commonly known as smog, forms when industrial pollutants emitted by cars, power plants, refineries and other sources chemically react in the presence of sunlight. High ozone levels can cause respiratory problems, including asthma and chronic bronchitis. People with compromised immune systems, the elderly and children playing outdoors are particularly vulnerable.

Judith Vale, New York’s deputy solicitor general, told the court that for some states, as much as 65% of smog pollution comes from outside its borders.

States that contribute to ground-level ozone must submit plans ensuring that coal-fired power plants and other industrial sites do not add significantly to air pollution in other states. In cases where a state has not submitted a “good neighbor” plan — or where EPA disapproves a state plan — a federal plan is supposed to ensure downwind states are protected.

What’s next for the rule?

The Supreme Court decision blocks EPA enforcement of the rule and sends the case back to the U.S. Court of Appeals for the District of Columbia Circuit, which is considering a lawsuit challenging the regulation that was brought by 11 mostly Republican-leaning states.

An EPA spokesman said the agency believes the plan is firmly rooted in its authority under the Clean Air Act and “looks forward to defending the merits of this vital public health protection” before that appeals court.

The spokesman, Timothy Carroll, said the Supreme Court’s ruling will “postpone the benefits that the Good Neighbor Plan is already achieving in many states and communities.”

While the plan is on pause, “Americans will continue to be exposed to higher levels of ground-level ozone, resulting in costly public health impacts that can be especially harmful to children and older adults,” Carroll said. Ozone disproportionately affects people of color, families with low incomes, and other vulnerable populations, he said.

Rich Nolan, president and CEO of the National Mining Association, said he was pleased that the Supreme Court “recognized the immediate harm to industry and consumers posed by this reckless rule. No agency is permitted to operate outside of the clear bounds of the law and today, once again, the Supreme Court reminded the EPA of that fact.”

With a stay in place, Nolan said the mining industry looks forward to making its case in court that the EPA rule “is unlawful in its excessive overreach and must be struck down to protect American workers, energy independence, the electric grid and the consumers it serves,.”

Few states participate

The EPA rule was intended to provide a national solution to the problem of ozone pollution, but challengers said it relied on the assumption that all 23 states targeted by the rule would participate. In fact, only about half that number of states were participating as of early this year.

A lawyer for industry groups that are challenging the rule said it imposes significant and immediate costs that could affect the reliability of the electric grid. With fewer states participating, the rule may result in only a small reduction in air pollution, with no guarantee the final rule will be upheld, industry lawyer Catherine Stetson told the Supreme Court in oral arguments earlier this year.

The EPA has said power-plant emissions dropped by 18% in 2023 in the 10 states where it has been allowed to enforce its rule, which was finalized last year. Those states are Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia and Wisconsin. In California, limits on emissions from industrial sources other than power plants are supposed to take effect in 2026.

The rule is on hold in another dozen states because of separate legal challenges. The states are Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah and West Virginia.

Administrative overstep or life-saving protection?

Critics, including Republicans and business groups, call the good neighbor rule an example of government overreach.

The EPA rule and other Biden administration regulations “are designed to hurriedly rid the U.S. power sector of fossil fuels by sharply increasing the operating costs, … forcing the plants’ premature retirement,” Republican lawmakers said in a brief filed with the high court.

Supporters disputed that and called the “good neighbor” rule critical to address interstate air pollution and ensure that all Americans have access to clean air.

“Today’s move by far-right Supreme Court justices to stay commonsense clean air rules shows just how radical this court has become,” said Charles Harper of environmental group Evergreen Action.

“The court is meddling with a rule that would prevent 1,300 Americans from dying prematurely every year from pollution that crosses state borders. We know that low-income and disadvantaged communities with poor air quality will bear the brunt of this delay,” Harper said.

Roger Reynolds, senior legal director of the environmental group Save the Sound, said the decision hinders the EPA from protecting states such as Connecticut and New York that suffer from ozone pollution generated in the Midwest.

“We cannot reach healthy air quality for our residents without addressing upwind pollution, in addition to local sources,” Reynolds said.

The rule applies mostly to states in the South and Midwest that contribute to air pollution along the East Coast. Some states, such as Texas, California, Pennsylvania, Illinois and Wisconsin, both contribute to downwind pollution and receive it from other states.

June 20, 2024

Texas’ main electric grid operator has sharply increased its prediction for how much power demand will increase in coming years. If it’s accurate, the state would need to be able to provide nearly double the amount of power within six years.

Two factors led to the higher forecast: A new law allows officials to count companies’ requests for grid connections before they are finalized. And there has been a significant rise in requests from large users such as data centers, hydrogen production facilities and oil and gas companies that are electrifying their operations.

On top of that, the state’s population continues growing, Electric Reliability Council of Texas President and Chief Executive Officer Pablo Vegas told state lawmakers in a Senate Business and Commerce Committee hearing last week, repeating information he shared with the ERCOT board in April.

“All of that is putting together a picture of a very significant, different demand growth that is forcing us to really re-think how we’re looking at planning to make sure we can meet those needs and continue to deliver on the expectations of all Texans,” Vegas told lawmakers.

Demand on the power grid hit a record of 85 gigawatts last year, which was the hottest ever recorded in the state. ERCOT experts now say demand could reach around 150 gigawatts by 2030.

More than a third of the forecast growth is coming from the Permian Basin, where oil and gas operators are converting operations to run on electricity instead of gas or diesel. Much is also coming from large users such as data centers that are powering artificial intelligence and crypto currency mining. Some are requesting several times more power than what the city of Lubbock now uses, according to ERCOT.

The new estimates raise crucial questions, such as whether large power users that can ramp up and down need greater state oversight, the committee’s chair, state Sen. Charles Schwertner, R-Georgetown, said in an interview. One bitcoin mining company last year reported making millions of dollars in the electricity market by selling back pre-purchased power when grid conditions became tight, which provoked the ire of some Texans who saw their power bills rise.

“I think we need to rise to the challenge of getting the needed generation onto the grid,” Schwertner said. “But there is eventually a prioritization that could be discussed, and obviously Texans — their families, their homes, their businesses — are the most important individuals, the most important clients for electricity.”

In a post on X after the hearing, Lt. Gov. Dan Patrick said the Legislature needed to “take a close look” at data centers and crypto operations. “We want data centers, but it can’t be the Wild Wild West of data centers and crypto miners crashing our grid and turning the lights off,” he wrote.

Electricity experts said the projected growth also makes clear that the grid will need more transmission lines — which are paid for by customers and take more time to build than many of the facilities that want more power.

“There’s no question there’s going to be additional need for generation,” said Michael Lozano, a communications and government affairs officer for the Permian Basin Petroleum Association. “But I think the most important thing right now that we’re trying to address is the lack of transmission.”

Previously, to plan for future transmission needs, ERCOT could only count power users that signed agreements with a utility, said Mark Bell, president of the Association of Electric Companies of Texas. House Bill 5066 allowed grid operators to count potential users without a signed agreement if the utility considered it “a serious project and very likely to interconnect,” Bell said.

Judging whether data centers will actually be built in Texas is difficult, said Katie Coleman, energy counsel for the Texas Association of Manufacturers, which represents large power users. Companies that want to build data centers could be “shopping around for places to do business,” she said, by making requests in multiple places where they might build.

Cyrus Reed, conservation director of the Lone Star Chapter of the Sierra Club, said demand could be lower if some projects never materialize. ​​“There’s a lot of unknowns,” Reed said, “but it’s what they’re putting into their system for planning purposes.”

“If I were ERCOT, I’d rather over predict so that we have more capacity, so we don’t have a shortage,” said Michael Webber, an energy resources professor at the University of Texas at Austin. “It’s hard to say whether it’s hype or whether it’s real.”

The state’s grid has come under intense public and legislative scrutiny since a 2021 winter storm crippled its operations, causing power outages across the state for days amid freezing temperatures that left millions of Texans without lights or heat. Hundreds died.

Lawmakers responded by requiring power facilities to prepare better to operate in extreme weather. They put $5 billion into a fund to give low-interest loans to companies that planned to build gas-fueled power plants, which legislators prioritized because they can provide power quickly on demand. State regulators are accepting applications for that money now.

Sen. Nathan Johnson, D-Dallas, a member of the Senate committee, said the need to meet higher demand could push innovation with renewable energy; drive more programs for people to use less power by making their homes or businesses more efficient; and spur ways for people and small businesses to get paid for using less power in tight times.

“This massive increase in load is going to provide greater momentum behind some very good trends,” Johnson said.

Disclosure: The Association of Electric Companies of Texas (AECT), Permian Basin Petroleum Association and University of Texas at Austin have been financial supporters of The Texas Tribune, a nonprofit, nonpartisan news organization that is funded in part by donations from members, foundations and corporate sponsors. Financial supporters play no role in the Tribune’s journalism. Find a complete list of them here.

This article originally appeared in The Texas Tribune at https://www.texastribune.org/2024/06/20/texas-electricity-demand-forecast-ercot/.

The Texas Tribune is a member-supported, nonpartisan newsroom informing and engaging Texans on state politics and policy. Learn more at texastribune.org.

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.”