ATLANTA (AP) — Utility regulators on Tuesday approved a plan for Georgia Power Co. to expand a power plant southwest of Atlanta.

The Georgia Public Service Commission voted 5-0 for the unit of Atlanta-based Southern Co. to build three new fossil-fuel burning units at Plant Yates, near Newnan.

The company has declined to say how much it will spend on the plants, which will burn either natural gas or diesel fuel to generate electricity, but commission staff members have said similar recent plants in other states have cost $800 million or more.

The commission greenlighted building the plants in April, when it approved a special plan to add generating capacity because the utility said demand was increasing more rapidly than previous projections, driven in part by a boom in computer data centers locating in Georgia. The company won permission to build the units itself, without seeking outside bids for electrical generation, because its projections show it needs more electricity by the end 2026.

“Simply put, we need to build these units and we need to build them now,” Georgia Power lawyer Steve Hewitson told commissioners Thursday during a committee meeting.

Normally, commissioners approve long-term generating and rate plans for Georgia Power once every three years, but this approval came mid-cycle. Because the regular generating and rate plans will be up for consideration next year, customers will see no change in bills because of Plant Yates until 2026.

Georgia Power customers have seen their bills rise sharply in recent years because of higher natural gas costs, the cost of construction projects, including two new nuclear reactors at Plant Vogtle near Augusta, and other factors. A typical Georgia Power residential customer now pays more than $173 a month, including taxes.

Environmentalists and customer advocates questioned letting Georgia Power build new fossil fuel plants without going through a competitive process. Using those sources would mean Georgia Power emits more climate-altering carbon dioxide than using solar generation, other renewable sources and conservation.

They also argue that it leaves customers more exposed to the risk of rising natural gas costs, which have been a big ingredient in recent bill increases. The units would mostly run on natural gas but would switch to diesel when electrical demand is at peak and more natural gas can’t be purchased or delivered by pipeline.

Curt Thompson, a lawyer representing the Sierra Club and the Southern Alliance for Clean Energy, argued Thursday that Georgia Power should bear some of the risks of rising natural gas costs. In Georgia, the company has been allowed to pass through the entire costs of fuel for its plants, including the combustion turbines it wants to build at Yates.

“The utility industry in general and Georgia Power, in particular, have become increasingly reliant on gas,” Thompson said. “The Yates CTs would only deepen that gas addiction.”

Opponents had again asked the commission to wait until it could examine bids to provide generation, even though commissioners had approved the Yates plan in April.

“Those resources may well be cheaper, cleaner, and a better fit for Georgia Power customers,” Thompson said.

Georgia Power agreed it wouldn’t charge for cost overruns for the turbines unless they are caused by factors outside the company’s “reasonable control.” It’s supposed to submit reports on construction progress every six months.

In their Q3 2024 results, the company announced an improved cash outlook, citing increasing demand for their grid and gas turbine businesses. Gas Services’ orders more than doubled year-over-year.

Specifically, Siemens Energy reports a new record for their order backlog at €120 billion ($131 billion) and revenue growth of 18.5%, with substantial growth in Grid Technologies, Transformation of Industry and Siemens Gamesa.

Commenting in a release, Siemens Energy’s president and CEO Christian Bruch attributed the positive backlog to increases in global energy consumption, which has resulted in demand and growth for their businesses.

Last year, the German government assisted with a counter-guarantee to support the company after their net loss of €4.5 billion ($5 billion) for the 2023 fiscal year, primarily due to the company’s ailing wind division, Siemens Gamesa.

For Q3 this year, the company reported a net loss of €102 million ($111.3 million).

Said Bruch: “The rapidly growing electricity market requires a wide range of our products. Especially our grid and gas turbine businesses are benefiting from this momentum.

“Importantly, with growing our order backlog, we have been able to improve its margin quality as well. Despite all the challenges, we are optimistic about the future and after the first nine months, we are well on track to meet our full-year guidance.”

Looking ahead, the company expects to achieve comparable revenue growth of 10 to 12% and free cash flow pre tax in a range of €1 billion ($1.1 billion) to €1.5 billion ($1.6 billion) for the fiscal year.

Said Bruch during a press conference call: “…quarter by quarter, we’re making headway. It’s not exciting, but it’s what we want to achieve.

“We expect that the global demand for power will continue to grow in addition to population growth and more electrification.”

Additionally, stated Bruch, new markets are opening up with the potential for growth: “New additional markets contribute to this. One topic, which is currently discussed everywhere is the power need for data centers – they make up a considerable part of our inquiries.

“And for the future, this means potential growth.”

Originally published by Power Engineering International.

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 proposed plants are the EmberYork Energy Center in Austin County and the EmberGreen Energy Center in Wharton County, both located in the Houston area. Both simple-cycle facilities would operate as peaker plants and can ramp up to their full capacity in under 10 minutes, EmberClear said.

The facilities are located near several large interstate natural gas pipelines and over 60 billion cubic feet of storage capacity. The newly constructed Matterhorn pipeline, with a capacity of 2 BCF per day, already connects to both facilities.

EmberClear said it has engaged with Houston-based ConocoPhillips to secure a firm gas supply for both projects, with ConocoPhillips maintaining firm capacity on the Matterhorn Pipeline.

The company is also into advanced discussions with a leading gas turbine manufacturer but did not say which one.

EmberClear applied for the loans through the Texas Energy Fund (TEF), a state government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

The launch of the loan program was driven by a projected surge in power demand in the ERCOT market.

ERCOT’s power demand is projected to grow from 86 GW to potentially 150 GW by 2030, rapidly outpacing power supply and creating significant challenges for key metropolitan areas.

Both EmberYork and EmberGreen could begin construction by Q1/Q2 2026.

In their respective second-quarter earnings reports, NRG Energy and Vistra discussed potential opportunities for data center co-location.

NRG’s 21 generating sites are “ideally suited for new large loads and power plant development, offering co-location opportunities both behind and in front of the meter,” said NRG President and CEO Larry Coben on the company’s earnings call Thursday.

Coben said NRG’s facilities would be attractive to data center developers for their access to water for cooling, premium fiber channel access for low latency and existing grid access for rapid market entry. NRG’s fleet includes a mix of natural gas, renewables and coal.

“We were getting lots of people sort of throwing us bids for our sites,” Coben told investors.

He continued: “We know they think we’re just a bunch of power guys who don’t know anything about data centers. So, if that’s what they’re bidding us, we really need to look at this, because it means there’s a lot more value in there than the bids that we’re receiving.”

Regarding discussions with data center providers and any potential co-location deals, Coben said NRG was working on a strategy and would release more details later in 2024.

The concept of large loads co-locating with generation continues to draw interest. The most-watched proposal would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in Pennsylvania.

Multiple utilities protested the proposed Talen Interconnection Service Agreement (ISA), prompting FERC to call for a technical conference in the fall to discuss the larger issue of co-location.

For Vistra, the pending Talen case or upcoming FERC technical conference “has not slowed the conversation down” on potential data center co-location deals, said company President and CEO Jim Burke.

“We’re in due diligence for a number of sites,” Burke told investors on the company’s Q2 call. “This is a really big opportunity for our industry to meet customer needs.”

Vistra reiterated the company can provide data centers the speed to market advantage since there wouldn’t be the same level of buildout needed on the transmission side.

“I think there’s going to be plenty of data center load behind-the-meter or co-located, and also front of the meter,” Burke said.

On planning for load growth and building new gas plants

The industry’s rapid load growth is being driven by data centers, electrification and new manufacturing. This is compounded by the retirement of fossil-fired plants. As a result, both NRG and Vistra see emerging supply gaps and tightening markets.

Among the regions expected to experience a surge in demand, ERCOT’s current long-term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission.

While NRG and Vistra operate plants outside of Texas, most of their growth is taking place in the ERCOT market. Both companies are taking advantage of the Texas Energy Fund (TEF), a government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

NRG has filed TEF loan applications for three separate projects, totaling more than 1,500 MW of capacity. Thee company would begin construction on two of the three facilities as early as October of this year.

One of these projects is a new 689 MW natural gas combined-cycle unit with Mitsubishi Power M501JAC equipment, located at NRG’s Cedar Bayou plant in Baytown, Texas. The target completion date would be late-2027.

The 415 MW simple-cycle unit at TH Wharton would include Siemens Energy’s SGT6-5000F equipment and could come online by mid-2026.

Finally, the 443 MW simple-cycle unit at Greens Bayou would be powered by a GE 7HA.03 turbine and could be finished by mid-2028.

“We believe our projects are well-situated for a timely approval, given their shovel-ready nature and the completeness of the applications that we submitted,” said Coben.

Texas Lt. Gov. Dan Patrick recently said 81 applicants representing over 41 GW of dispatchable power had applied through the fund, as of May 31. Patrick said the state planned on expanding the program during the next legislative session.

Coben told investors NRG could apply for more loan funding in a potential second TEF round, but also noted the challenge of multi-year lead times for turbines and other equipment.

“If you don’t have a place in the turbine queue today, there’s no way you’re getting a new project online before 2030, at the earliest,” he said.

In May, Vistra announced plans to add up to 2,000 MW of natural gas-fired capacity in West, Central and North Texas.

860 MW of simple-cycle peaker plants would support West Texas, including the state’s growing oil and gas industry. The company is seeing multiple demand drivers, including data centers and the electrification of oil field operations, specifically the Permian Basin of West Texas

Vistra would also convert its coal-fired Coleto Creek plant near Goliad to natural gas after the plant retires in 2027. Repowering would enable up to 600 MW of gas-fired capacity.

Also included are 500 MW of augmentations at existing facilities, nearly half of which are already finished, Burke said on the Q2 earnings call.

In its quarterly report, Vistra leadership noted the industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment needed for the construction of renewables projects. As a result, Vistra has deferred some of planned capital spend for these projects, the company said in its 10-Q filing.

The company did announce two long-term power purchase agreements (PPAs) with Amazon and Microsoft for two new large-scale solar facilities.

Supply chain disruptions have also increased the lead times to procure certain materials necessary to maintain Vistra’s natural gas, nuclear and coal fleet, according to the filing.

“We have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages,” the company reported.

In its Q2 report, NRG said procuring mid to long-term generation through PPAs continues to be part of its strategy. The company has entered into renewable PPAs totaling nearly 1.9 GW with third-party developers, all of which were operational as of July 31.

The Cogentrix fleet includes 11 natural gas-fired power plants totaling 5.3 GW located throughout PJM, ERCOT and ISO-NE.

Cogentrix is headquartered in Charlotte, North Carolina and has multiple decades of experience acquiring, developing, constructing, operating and optimizing conventional and renewable power generation assets throughout the U.S. Following transaction close, the company will continue to be led by current CEO John Ragan and the existing Cogentrix management team.

On the 5+ GW buy, Quantum cited rapidly increasing electricity demand due to the growth of data centers and AI, the reshoring of manufacturing and electrification, as well as the retirements of fossil-fired generation.

The transaction is subject to customary regulatory approvals and is expected to close between the fourth quarter of 2024 and the first quarter of 2025.

Guggenheim served as Quantum’s financial advisor while King & Spalding and Vinson & Elkins provided legal advice to Quantum. Lazard served as Carlyle’s financial advisor and Latham & Watkins as legal advisor.

Georgia Power is celebrating Generation Appreciation Month, a time to recognize the more than 1,100 team members who “work tirelessly in power plants across state to keep reliable energy flowing to the grid on hot summer days, cold winter mornings and every hour in between.”

“In life, as well as with Georgia Power’s power generation facilities, there is no one-size-fits-all option,” said Rick Anderson, senior vice president and senior production officer for Georgia Power. “From the existing facilities that have powered Georgia for decades, to newer sources of generation such as renewable energy, cleaner natural gas and battery storage, Georgia Power’s diverse generation mix continues to evolve to meet the needs of a growing Georgia. To keep the energy flowing, we need a workforce that is just as advanced and diverse.”

Based on available opportunities, a career in power generation offers many possibilities for those who join the team, Georgia Power said. Career paths exist in the areas of operations, maintenance, electrical, instrumentation, engineering and more. Last year, the company hired over 80 team members across generation facilities and expects the hiring trend to continue in the coming years. Strong training programs exist in Operations, along with apprenticeships in Mechanical and Electrical, which develop experienced journeymen who work safely to keep energy flowing to the grid, 24/7.

Georgia Power also highlighted the “continuous learning” it offers, including the Rockmart training facility where electrical, mechanical, and instrumentation and control technicians hone their skills each year. In 2023, this facility conducted nearly 3,000 hours of both hands-on and classroom instruction. Subject matter experts from both Southern Company and external entities visited to assist in this training program.

The total $1.1 billion investment in Indiana’s Pike County would take place from 2024 to 2026.

Petersburg Generating Station Units 3 and 4 would be repowered from coal to natural gas by the end of 2026. AES Indiana anticipates being the first utility in Indiana out of coal, pending approval of the project from state regulators.

The Petersburg Energy Center would add 250 MW of solar and 180 MWh of battery storage to AES Indiana’s portfolio. The project is currently under construction and expected to be operational by the end of 2025.

AES Indiana’s 2022 Integrated Resource Plan (IRP) includes transitioning coal-powered units to natural gas and adding wind, solar and battery storage capacity over the next five years.

Recently, AES Indiana acquired 100 percent interest in Hoosier Wind, a 106 MW wind project in Benton County and announced the commercial operation of the Hardy Hills 195 MW solar project in Clinton County.

The portfolio, totaling 300 MW, includes Edgewood Energy, LLC, Shoreham Energy, LLC, Pinelawn Power LLC, and Equus Power I, L.P., all located on Long Island.

Upon the close of this transaction, HSE affiliates will own approximately 2,650 MW of gas-fired and dual-fueled generation capacity operating as part of the Milepost Power fleet.

In December 2023 Hull Street closed a $160 million financing for its 855 MW Milepost Power Texas portfolio known as Mesquite Generation. The plants in the Mesquite portfolio are located in Bastrop and Paris, Texas. HSE is headquartered in Beethesda, Maryland.

Troutman Pepper acted as legal counsel to HSE. CIBC Capital Markets and Merit Capital Advisors acted as financial advisors and Baker McKenzie acted as legal counsel to J-Power.

J-POWER is one of the world’s largest independent generators of electricity, owning 96 power plants in Japan and 35 international IPP investments.