Alabama Power is paying less for power generated by third-party energy producers and imposing a cost for those companies to connect to its electricity grid.

The rule was approved by the Alabama Public Service Commission (PSC) in March; took effect in April and applies to companies that can generate at least 100 kilowatts of electricity.

Alabama Power said in an emailed statement the rates are updated each year, based on fuel costs and inflation, to keep prices as affordable as possible.

The company also said in a separate statement that the new integration cost is part of the monthly energy payment that the company pays to energy providers who are not Alabama Power customers.

Critics allege that the maneuvers are meant to stamp out competition in the market for electricity, especially for solar power providers looking to gain a foothold in the central and southern parts of the state and compete with Alabama Power.

“It is 100% about control,” said Steve Cicala, associate professor of economics at Tufts University, whose work focuses on the economics of regulation, particularly with respect to environmental and energy policy. “They are a business — and they don’t want competition.”

Daniel Tait, executive director for Energy Alabama, an advocacy group that hopes to increase renewable energy generation in the state, said Alabama Power was “trying to protect their monopoly, first and foremost.”

“It doesn’t really matter about the energy source,” he said. “Solar is just the one that is the most economical and the one most likely to challenge that monopoly, so that is why you see the fight on solar.”

The Alabama Public Service Commission said in a statement that the rate adjustments are appropriate based on the figures that Alabama Power provided.

“The cost is driven by the magnitude of the intermittency of certain generation, which requires additional operating reserves to maintain reliability on our system,” Alabama Power said in its email.

But some experts say the intermittency argument is overstated.

“We have gotten really good at predicting solar and wind output,” said Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. “These are large-scale industries in the U.S. and there are many gigawatts of wind and solar being developed each year.”

Both Energy Alabama and the Southern Renewable Energy Association, another group that promotes the responsible use of alternative energy, sought to challenge the PSC’s ruling, but the PSC officially denied their request in a written order on July 22.

Tait said Energy Alabama has decided not to challenge the order in court and will wait until the following year, should Alabama Power request a rate update or rule change with the PSC.

The Southern Renewable Energy Association said it is still considering its options.

Solar charges

The most recent rule changes limit revenues for larger renewable energy companies with power-producing plants. Those are separate from the households and smaller solar-producing companies that also generate electricity.

“The utilities have been lobbying for this for a long time,” said Gilbert Michaud, assistant professor with the School of Environmental Sustainability at Loyola University Chicago. “Utilities are having more competition in their sandbox, and they are saying, ‘We really don’t want more distributed solar generation because folks will buy less power from us. But we still have to maintain all our power plants and the grid infrastructure.’”

Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. said the ruling would discourage third parties from investing in renewable energy projects.

“While every solar project has different economic requirements, lowering the price a solar project receives or adding additional fees likely means fewer projects will get built, less investment in communities that would host those projects, few jobs in building those projects, etc,” he wrote in an email. “If the price received by a solar project is lower than the cost of operating Alabama Power’s own power plants, that’s also a missed opportunity for the utility’s electric customers to save money.”

The grid

Alabama Power, the largest utility in the state, has nearly 1.5 million customers and provides electricity to 57% of all customers in Alabama, according to a 2020 report published by the Southeast Energy Efficiency Alliance.

In February, Alabama Power filed a document with the PSC, the state’s electricity regulator, that proposed cutting the rates they pay for third-party electrical generation, known as a Contract for Purchased Energy (CPE), by up to 50%. In one category, the price decreased from about 7.33 cents per kilowatt hour to about 3.65 cents per kilowatt hour.

Those figures are formulated through a model and the values are estimated. That can be subjective, according to Pierpont of Energy Innovation.

“What they do is estimate low avoided costs, so they don’t have to pay very much,” Pierpont said. “In the meantime, they’re running coal plants and gas plants that cost quite a bit more than the rate they would be paying under this type of contract.”

Throughout the country, Pierpont said, power distribution companies like Alabama Power have been working to reduce the amount they pay homeowners who contribute electricity back to the grid through rooftop solar panels.

In addition to the lower rate payments, Alabama Power introduced a Variable Integration Cost at $0.00193 per kilowatt hour for third-party companies. That would further reduce the revenue that those firms receive for energy purchased by Alabama Power.

Pierpont found a few examples of utility companies imposing an integration cost to connect to the system. One is PacifiCorp, an energy company that operates in several western states, and the second is Duke, which is in the Carolinas.

“This approach seems fairly rare and limited to regions without competitive electricity markets,” Pierpont wrote in an email.

Significant costs

Energy Alabama published a blog post in June alleging that the charges, which it called a tax, would amount to a $250,000 annual charge for an 80-megawatt solar farm based in Montgomery.

The updated rates, along with the integration cost, are separate from the charges that Alabama Power imposes on individual households who install solar to offset their electricity bill.

In 2012, the PSC approved an Alabama Power request to impose a $5 per kW Capacity Reservation Charge (CRE) on customers with solar panels, often known as a rooftop fee. Typically, households that generate about 5 kW on their solar array will pay about $300 annually, or $9,000 over the 30-year expected lifespan of the system.

That charge has since increased to $5.41.

Power companies in other states have been allowed to impose such charges, including Arizona. Michaud, at Loyola University in Chicago, estimates that residents in almost a third of all the states in the country must pay such a fee. Michaud said the fees are clustered “in more conservative states, like the U.S. South.”

This makes it less economical for households to install solar panels for their homes because they make up the upfront fixed cost of the system from the savings generated from their power bills, and lengthens the time needed to recoup the cost of the system.

“It is basically killing your payback period, or at least increasing it,” Michaud said. “I would do this in my class, and a lot of students find, ‘Hey, this increases the payback period from 10 years to 14 years.’ You are having folks paying for a longer time.”

‘Intermittency of certain generation’

For its part, Alabama Power said the rate adjustments to third-party energy providers, also known as the CPE, and newly imposed integration cost, are necessary for maintaining price stability for customers.

“Rate CPE keeps electricity costs stable for customers by ensuring Alabama Power pays a fair price for energy,” the company said in an emailed statement. “This approach, updated annually, protects customers from unexpected price shocks linked to fluctuating energy production costs.”

The company said that the Variable Integration Cost is not a fee and is factored into the calculation that Alabama Power pays third-party producers who are not customers of Alabama Power and who sell all their output to the company.

“The cost is driven by the magnitude of the intermittency of certain generation, like solar, which requires additional operating reserves to maintain reliability on our system,” the company said.

When electricity is in high demand, electricity third-party providers contribute is highly valuable. The power becomes less valuable very late in the evening or very early in the morning, the times when people are asleep, not very active, and have no need for electricity. Smoothing out the supply when the need is uncertain is a tricky question to answer.

Timothy Charles Lieuwen, a professor of engineering at Georgia Tech University, said that over time, the price power distribution companies have been willing to pay to third parties who generate energy has declined.

“It is a really hard question, what is the value of the power they (third party energy providers) are providing,” he said.

Power distribution companies, including vertically integrated ones such as Alabama Power, are less willing to purchase power from other companies in the face of that mounting uncertainty about when customers will need that energy.

The Public Service Commission deferred to Alabama Power in an emailed statement.

“The adjustments to Rate CPE (Contract for Purchased Energy) were found to be in the public interest because they accurately reflected Alabama Power Company’s most current projected avoided cost,” the statement said. “Alabama Power’s projected avoided costs are updated annually. The variable integration charge was approved because it mitigates the cost incurred with integrating the intermittent output of QFs (Qualifying Facilities) onto the Southern Company System.”

The Public Service Commission said in its statement that allegations that it gave Alabama Power more control over the electricity production market were not valid.

“The matters approved in the Commission’s March 5, 2024 Order in Docket U-5213 were designed to accurately establish the projected avoided cost rates for CPE and to allow for the recovery of the cost incurred by Alabama Power in integrating the intermittent output of QFs onto the Southern Company System,” the statement said.

Tait called Alabama Power’s claims about intermittency “absurd.”

“Basically, what Alabama Power is saying when they say something like that is, ‘Our engineers are dumber than everybody else’s engineers and they can’t figure this out,’” Tait said. “Alabama Power’s engineers are just as smart, and just as talented, as everybody else is.”

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

Fund V will invest in power and energy infrastructure assets, platforms, and companies, LS Power said.

“Demand for electricity in the United States is growing at the fastest rate in decades, driven by electrification, data center proliferation, and an American manufacturing renaissance.,” Paul Segal, CEO of LS Power, said. “Our portfolio of assets and businesses—which spans generation, transmission, and decarbonization solutions—is designed to ensure the reliability and affordability of electricity while accelerating the energy transition. We look forward to investing this capital to help meet the historic challenges facing the U.S. energy sector.”

Since its inception, LS Power has raised $60 billion in debt and equity capital and developed and acquired more than 47 GW and 160 power generation projects to support North American energy infrastructure. In addition, LS Power Grid has developed 16 transmission projects, including 6 utilities in operation across 5 ISO/RTOs that serve 185 million people. These projects include 780+ miles of high voltage transmission, beyond which LS Power Grid has another 350+ miles in development. 

LS Power said it will leverage its market knowledge, industry network, and in-house expertise to invest Fund V’s capital. To date, Fund V has invested or committed approximately $1.6 billion across renewable and gas-fired generation, renewable fuels, and green hydrogen, with an extensive pipeline of additional opportunities. Recent investments include the announced acquisition of Algonquin Power & Utilities Corp.’s North American renewable energy business, comprised of 3 GW of operating projects and an 8 GW development pipeline spanning 12 states, 4 provinces, and 5 U.S. power markets.

“Over the past thirty years, LS Power has built a platform to meet this moment in the energy transition,” said Darpan Kapadia, Chief Operating Officer of LS Power. “The success of this fundraise is a testament to our team’s deep expertise and strong track record through multiple market cycles. We are grateful to our investors, both new and long-standing, for their partnership.”

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.

“When more electricity generation capacity is needed and reserves begin to tighten, a well-designed competitive market sends the appropriate signals to generators to spend capital on both new and existing sources. We received that message loud and clear,” said Caleb Stephenson, Calpine EVP of Commercial Operations.

Over the last decade, Calpine has brought online 1,600 MW of new gas-fired generation within PJM territory. PJM is the largest grid operator in the U.S.

Last month, PJM announced the results of its latest power market auction. The auction produced a price of $269.92/MW-day for most of the PJM footprint, compared to $28.92/MW-day for the 2024/2025 auction. The more than 800% increase expects to have a massive ripple effect across PJM’s 13-state footprint.

Insufficient future transmission planning, the retirement of fossil-fired generation, long interconnection queues and the implementation of FERC market reforms are all contributing to the price hikes.

While Stephenson said the auction results send a build signal to Calpine and other power producers, he said “clarity regarding state-level air emissions regulations is needed for projects to move forward in Pennsylvania.”

After seeing positive market signals in Texas, Calpine began redevelopment efforts in the Lonestar State last year. The company is reportedly on track to add over 1,000 MW of generation to its Texas fleet over the next few years.

“We are increasing staffing and are looking forward to bringing more generation online in PJM as well,” added Stephenson.

COLUMBIA, S.C. (AP) — The South Carolina Senate on Thursday started its homework assignment of coming up with a comprehensive bill to guide energy policy in a rapidly growing state and amid a quickly changing power- generation world.

The Special Committee on South Carolina’s Energy Future plans several meetings through October. On Thursday, the committee heard from the leaders of the state’s three major utilities. Future meetings will bring in regular ratepayers, environmentalists, business leaders and experts on the latest technology to make electricity,

The Senate took this task upon itself. They put the brakes a massive 80-plus page energy overhaul bill that passed the House in March in less than six weeks, and the bill died at the end of the session.

Many senators said the process earlier this year was rushed. They remembered the last time they trusted an overhaul bill backed by utilities.

State-owned Santee Cooper and private South Carolina Electric & Gas used those rules passed 15 years ago to put ratepayers on the hook for billions of dollars spent on two new nuclear reactors that never generated a watt of power before construction was abandoned because of rising costs.

But those dire memories are being mixed with dire predictions of a state running out of power.

Unusually cold weather on Christmas Eve 2022 along with problems at a generating facility nearly led to rolling blackouts in South Carolina. Demand from advanced manufacturing and data centers is rising. If electric cars grow in popularity, more power is needed. And a state that added 1.3 million people since 2000 has a lot more air conditioners, washing machines and charges for devices, the utility leaders said.

Senators stopped Duke Energy’s president in South Carolina, Mike Callahan, in middle of his presentation after he told them his utility’s most recent predictions for growth in electricity usage over the rest of this decade were eight times more than they were just two years ago.

“Growth is here, and much more is coming. We need clear energy policy to plan for that growth,” Callahan said,

The utility leaders told senators their companies need to know what kind of sources of power — natural gas, solar, nuclear, wind or others — the state wants to emphasize. They would like to have a stable rules from regulators on how they operate.

“A quick no is a lot better to us than a long-term maybe,” Santee Cooper CEO Jimmy Staton said.

Another complicating factor are federal rules that may require utilities to shut down power plants that use coal before there are replacements with different sources online, Staton said.

Others aren’t so sure the state needs a rapid increase in power generation. Environmentalists have suggested the 2022 problems that led to blackouts were made worse because power plants were nowhere near capacity and better cooperation in the grid would allow electricity to get to where its needed easier.

Those less bullish on the overhaul also are urging the state not to lock in on one source of power over another because technology could leave South Carolina with too much power generation in inefficient ways.

There will likely be plenty of discussion of data centers that use a lot of electricity without the number of jobs, property taxes or other benefits a manufacturer provides.

Staton estimated about 70% of Santee Cooper’s increased demand is from data centers.

“We clearly need them. I don’t want to go back in time,” committee chairman Republican Senate Majority Leader Shane Massey said. “What I’m trying to get at is a better understanding, a better handle on how much of the projected growth is based on data centers or on everything else.”

Massey has been hard on Dominion Energy, which bought South Carolina Electric & Gas after the abandoned nuclear project at the V.C. Summer Nuclear Station. But Dominion Energy South Carolina President Keller Kissam said it is important that all options, including a new nuclear plant, remain on the table.

“Everybody thinks if we build anything that we’re going to absolutely repeat what we did with V.C. Summer” Kissam said. “Well, I promise you, that ain’t gonna happen. OK? I’ll pack up and leave.”

Massey said he appreciated Kissam’s candor and felt he was a straight shooter, but there are a lot of other people involved in the failed project who lied and hid problems.

“I can’t put that behind me. And I don’t think a lot of people can put that behind them,” Massey said.

Massey’s goal is to have a bill ready by the time the 2025 session starts in January.

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.