The power station operates two nuclear reactors in Louisa County, Va. Dominion Energy’s Surry Power Station previously received NRC approval in 2021 to extend its operating license through 2053. Combined, Surry and North Anna generate 40% of Virginia’s electricity and account for about 90% of the carbon-free power in the state.

“For more than 50 years, nuclear power has been the most reliable workhorse of our fleet and the largest source of carbon-free power in Virginia,” said Eric Carr, Dominion Energy’s chief nuclear officer. “North Anna operates around the clock and generates the reliable, clean energy that powers our customers’ homes and businesses every day. With this 20-year extension, our customers can continue counting on North Anna for reliable, carbon-free power for another generation to come.”

Dominion Energy said it is conducting numerous upgrades at the station, including replacing the reactors’ main generators and condensers, refurbishing reactor coolant pumps, and converting instrument and control systems from analog to digital. The company is also implementing 80 enhancements to station procedures, such as additional inspections and equipment testing.

The North Anna units were originally licensed to operate for 40 years in 1978 and 1980. Their licenses were renewed for an additional 20 years in 2003, after a federal review process. Under its current licenses, North Anna reactors 1 and 2 could have operated through 2038 and 2040, respectively. With the renewed licenses, the units can operate through 2058 and 2060, respectively. 

Dominion Energy said it plans to seek recovery of the costs associated with the license extension from the Virginia State Corporation Commission later this year.

The nuclear units at North Anna Power Station are both three-loop Westinghouse pressurized water reactors – capable of providing nearly 2,000 MW at peak capacity, or about 17% of the electricity delivered to Dominion Energy Virginia customers.

Dominion Energy’s affiliated companies also plan to seek NRC approval to extend to 80 years the operating licenses of the V.C. Summer Power Station in South Carolina and Millstone Power Station in Connecticut.

Earlier this year, Dominion Energy Virginia issued a Request for Proposals (RFP) from nuclear technology companies to evaluate the feasibility of developing a small modular reactor (SMR) at the North Anna Power Station. While Dominion stressed the RFP is not a commitment to build this SMR, the company said it is an important first step in evaluating the technology and the North Anna site.

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.

Data centers being rapidly built in the West are becoming an “emerging risk” to electrical grid reliability in the region, according to regional transmission experts. 

New data centers, which can be built in as little as 18 months, are far outpacing the growth in new electrical energy supply and transmission, according to members of the Western Electricity Coordinating Council, a nonprofit organization based in Salt Lake City that ensures grid connection and reliability between utilities in 14 western states and parts of Canada and Mexico. Members of the council discussed challenges to grid reliability at a recent webinar first reported by the trade publication RTO Insider. 

In it, council members said new energy demand from data centers has emerged as a more prescient challenge than meeting energy demand for transportation, also becoming rapidly electrified. The energy and transmission buildout needed to meet these demands is lagging, they said. By the end of 2023, just about half of the new energy buildout anticipated for the West had been completed. This is due in large part to supply chain issues, prices and skilled labor shortages, according to Branden Sudduth, the commission’s vice president of reliability planning. 

There are more than 700 data centers within those 14 states, including 109 in Oregon, according to the company Data Center Map, and there are more than 5,000 data centers throughout the U.S. according to Statista – the most for any single country in the world. 

Oregon’s data center market is the fifth largest in the nation, according to Chicago-based commercial real estate group Cushman & Wakefield. Amazon, Apple, Facebook, Google and X, formerly named Twitter, have massive data centers in eastern Oregon as well as in The Dalles, Hillsboro and Prineville that require enormous amounts of energy to operate. Amazon is planning to build at least 10 more data centers in eastern Oregon, according to reporting by The Oregonian/OregonLive.

“We’re going to see an industry that wants to come online quickly with very large loads, and how are we going to address that?” Sudduth said.

The council in 2023 projected that demand for electricity in the West would increase about 17% by 2033 – that’s about twice what it had predicted just the year before. That leap in projected energy use is due largely to the number of large data centers being built, they said. Data centers run on large amounts of energy needed for processing and for cooling servers.

The Portland-based industry trade group Pacific Northwest Utilities Conference Committee has projected electricity demand to grow 30% in the region in the next decade, also due in large part to data centers. 

Another major challenge to grid reliability discussed was extreme weather. Sudduth said more energy sources and transmission would need to be developed both at the local level and across the region to ensure a reliable electricity supply.

“Pretty much since the August 2020 heat wave event, the weather patterns that we’re experiencing are different from what we’ve typically planned for in the past. A lot of the weather events are more widespread and they last a lot longer than they have in the past,” Sudduth said.

A growing number of utilities in Oregon and Washington are joining a new western regional market for buying and selling energy from one another at set prices for the day ahead, so that they can better handle demand spikes during extreme weather events, such as heat waves or ice storms. The Bonneville Power Administration – responsible for about 28% of all power consumed in the Northwest – is expected to announce soon whether it will join most other Western utilities in this Western day ahead market, or go to a competing day ahead market run by the Southwest Power Pool, based in Arkansas.

Oregon Capital Chronicle is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Oregon Capital Chronicle maintains editorial independence. Contact Editor Lynne Terry for questions: info@oregoncapitalchronicle.com. Follow Oregon Capital Chronicle on Facebook and X.

“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.

CenterPoint said respondents are encouraged to submit proposals that include utility-scale solar, wind and storage projects (standalone or paired), along with thermal generation, load-modifying resources, demand-side resources and other innovative solutions

“This RFP allows us to explore a wide range of technologies that can contribute to our long-term generation strategy,” said Shane Bradford, CenterPoint’s Vice President for Indiana Electric.

Proposals are due October 8, 2024, the company said.

Last year CenterPoint released its resource plan for Indiana, calling to reduce carbon emissions from its generation fleet by more than 95% over the next 20 years. This would include ending its use of Indiana coal by 2027.

At the time, the company said by 2030, it expected more than 80% of CenterPoint Energy’s electricity to be generated by solar and wind, with the rest provided by natural gas.

The assessment focuses on the viability of the council’s 2021 Power Plan resource strategy and finds implementing it — specifically achieving energy efficiency consistent with the high end of the council’s target, pursuing renewable deployment of around 6,600 MW by 2029, and ensuring sufficient balancing resources and demand response — will provide for an adequate system.

That analysis comes with a caveat, however. Pursuing the low end of the council’s energy efficiency target would not provide for an adequate system, and if data center load growth accelerates and more closely aligns with utility projections in the region by 2029, the resource strategy will be insufficient, indicates the report.

The council uses an adequacy model called GENESYS to simulate the region’s bulk power system. In each simulation (which represents one year), a simulated shortfall event occurs over a time period when load cannot be served by resources in the model. Each modeled shortfall signals that emergency measures are necessary to avoid a blackout, like expensive cost resources not in an active utility portfolio, high-priced market purchases above normal import limit (such as those that occurred during January 2024’s winter storm event), calls for conservation by government officials (as in September 2022 California heatwave), or curtailment of fish and wildlife hydro operations (as happened during the 2001 Energy Crisis).

The assessment accounts for system changes that will be implemented by 2029, including load growth, in-region resource developments, and out-of-region market fundamentals. Electric load is expected to substantially increase by 2029, thanks to data centers and electric vehicles. However, announced changes to thermal plant retirements, such as Valmy 1 & 2 and Jim Bridger 1 & 2 conversions from coal to gas fueling, and anticipated transmission expansion throughout the WECC, including Boardman-to-Hemingway in the region, appear to alleviate some of the challenges associated with the increased loads when coupled with the 2021 Plan’s resource strategy.

The Pacific Northwest’s hydroelectric system provides more than half the grid’s nameplate capacity. The region has historically had an excess of peaking capacity but continues to be limited by the water supply that powers the hydroelectric system. Due to significant increases in variable energy resources, changes in hydroelectric operating constraints, and other added complexities, the region can no longer assume that it has sufficient capacity to meet all demand; thus, it is important to include a metric to protect against excessively high-capacity shortfalls, argues the report.

From an adequacy perspective, while hydropower is slightly reduced, based on the limited subset of studies used for a comparative study, the changes do not lead to a significantly different regional adequacy result. Offsetting the reduced hydropower is a small increase in regional thermal generation and market reliance, yet within the market reliance limit, throughout most of the year, especially at night.

The 2021 Power Plan’s resource strategy recommends that between 750 and 1,000 average MW of cost-effective energy efficiency, at least 3,500 MW of renewable resources, and 720 MW of low-cost and frequently deployable demand response be acquired, as well as increasing balancing up reserve requirements to 6,000 MW to respond to growing short-term uncertainty in variable energy resources (primarily wind and solar) by 2027.

The report acknowledges other changes to the regional power system that are important to consider since the 2027 assessment, including announced thermal retirement changes of coal-to-gas conversion, expanded transmission capacity, and hydro changes from the Resilient Columbia Basin Agreement to the Lower Snake and Lower Columbia projects.

The funding would support technologies that capture CO2 from industrial and power generation or directly from the atmosphere and transport it either for permanent geologic storage or conversion into valuable products such as fuels and chemicals.

The sixth opening of FECM’s Carbon Management funding opportunity announcement (FOA) will support the following areas of interest:

• Reactive carbon capture approaches for point source capture or atmospheric capture with integrated conversion to useful products. Reactive carbon capture is the integration of carbon capture with conversion to a product. This area of interest would focus on conceptual design studies followed by laboratory validation of reactive CO2 capture approaches from exhaust flue gas streams at electric generation and industrial facilities or from the atmosphere, with conversion of the CO2 into environmentally responsible and economically valuable products.
   
• Engineering-scale testing of transformational carbon capture technologies for natural gas combined cycle (NGCC) power plants. Testing under real flue gas conditions aims to achieve 95 percent or greater carbon capture efficiency and 95 percent CO2 purity, while demonstrating significant progress toward a 30 percent reduction in the cost of capture.
   
• Engineering-scale testing of transformational carbon capture technologies in portable systems at industrial plants. Development and testing of portable systems for transformational technologies would be conducted at a variety of sites, including oil refineries and petrochemical, cement and lime, pulp, steel and iron, and glass plants.
   
• Preliminary front-end engineering design (Pre-FEED) studies for carbon capture systems at existing (retrofit) domestic NGCC power plants. Pre-FEED studies of commercial-scale, advanced carbon capture systems at existing NGCC power plants or combined heat and power facilities that employ NGCC power generation.
   
• Pre-FEED studies for carbon capture systems at hydrogen production facilities using coal, mixed coal/biomass or natural gas feedstock. Studies to advance commercial-scale carbon capture systems that separate CO2 with at least 95 percent capture efficiency at new or existing hydrogen production facilities using coal, mixed coal/biomass/municipal solid waste/unrecyclable plastics, or natural gas feedstocks.
   
• Enhancing CO2 transport infrastructure (ECO2 transport): Pre-FEED studies for multimodal CO2 transfer facilities. Studies that support the development of viable and strategically adaptable multimodal transportation infrastructure capable of transferring CO2 across regional and national CO2 transportation networks.

Aypa Power intends to develop, own, and operate a 150 MW/600 MWh battery storage facility in Kuna, Idaho just outside the capital of Boise. Aypa’s secured financing package includes a $233 million green loan, including a construction and term loan, a tax equity bridge loan, and a letter of credit facility. Additionally, the project secured $90 million in tax equity, bringing the total financing to $323 million. The company secured a 20-year agreement with Idaho Power last year and hopes to bring it online in 2025.

Renewable Energy World asked Aypa Power to see if the Idaho battery storage project requires any additional state or local approval and is awaiting a response. It’s a natural question for any clean energy project proposed in Idaho given a recent trend of local opposition.

Kuna residents recently came out in force against the 2,385-acre Powers Butte Energy Center solar project developed by Savion, Idaho News 6 reports. The proposed solar farm would be located in a rural farming area, much to the annoyance of the opposition, who say the farm would be a blight on the surrounding area.

Kuna residents attended the second public hearing on the Powers Butte Energy Center project, but Ada County Commissioners did not make a decision on the project’s future. By the end of the month, the Ada County Commission moved to halt on the project, BoiseDev reports, citing public opposition and their own feelings in their decision. Commissioners said the project would come with environmental concerns and unfavorable views.

Ryan Davidson, an Ada County Commissioner, called the decision “tough” and said the board he serves on is “not anti-solar.” He said the commission previously approved a Savion solar project that was developed “out in the desert,” instead of near residents.

It’s not just solar that faces an uphill battle in Idaho: a controversial wind project is facing another obstacle after Sen. Jim Risch introduced legislation to delay the 1,000 MW Lava Ridge Wind project, which is located on federal land near the Minidoka National Historic Site. The project’s opponents claim that the wind farm will “visually compromise” the historic site honoring more than 13,000 Japanese-Americans who were incarcerated during World War II.

Opposition to the Lava Ridge Wind project led the Bureau of Land Management to suggest nearly halving the size of the project from 400 turbines to 241 as part of the “preferred alternative” plan. Idaho’s state legislature unanimously passed a resolution in March 2023 expressing opposition to the Lava Ridge Wind Energy Project.

Based on local reporting, Idaho residents haven’t appeared to have objected to any battery storage project, though Aypa’s would be the state’s first utility-scale facility.

Idaho Power, the investor-owned utility providing electricity to most of the state, sees energy storage serving a key role in the future. Last year, the utility laid out a plan to acquire 101 MW of energy storage to address potential capacity shortfalls driven by limited third-party transmission capacity, load growth, and declining peak performance from several resources, NewsData reports. Some of that load growth will come from a Meta data center that’s expected to be completed in 2025.

While opponents of wind and solar — referred to unaffectionately as “NIMBYs,” an acronym for Not in My Backyard — have successfully fought projects across the country, the majority of Americas don’t mind living near clean energy projects, according to polling data.

A Washington Post-University of Maryland poll found around 75% of Americans are comfortable living near solar projects. Wind projects faired slightly worse at 70%. The poll did not ask about energy storage projects.

Despite broad support for clean energy projects in the U.S., at least 15% of counties have “halted new utility-scale wind, solar, or both,” according to a USA Today report, by implementing “outright bans, moratoriums, construction impediments, and other conditions.”

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.