The three facilities are the 200-MW Huck Finn Renewable Energy Center, the 150-MW Boomtown Renewable Energy Center and the 150-MW Cass County Renewable Energy Center.

Both the Cass County and Boomtown facilities will serve Ameren Missouri’s Renewable Solutions program. Organizations from across Missouri signed up to take part in the program, increasing their use of renewable energy and supporting its development in the region. As part of the program, participating organizations will also receive renewable energy credits.

Ameren Missouri is also working toward the construction of additional new sources of energy. In 2027, an 800-MW simple-cycle natural gas energy center is expected to be ready to serve as a backup source of energy. The Castle Bluff Energy Center represents an investment of approximately $900 million, and its proposed site previously hosted the coal-fired Meramec Energy Center, which Ameren closed in 2022. The utility owns the property and already has existing infrastructure and transmission line access, reducing the construction costs of the project, Ameren said. Pending regulatory approval, construction would begin in 2026.

Last October, Ameren released its 2023 Integrated Resource Plan, which included investments in natural gas, renewables and battery storage. One of the highlights of the IRP included building an 800 MW simple-cycle plant. Others included:

• Moving back the previously announced addition of a combined-cycle energy center to 2033. This 1,200 MW facility is now scheduled to go in service following the retirement of the Sioux Energy Center in 2032.
• Accelerating Ameren Missouri’s planned renewable energy additions by four years. The company plans to add 4,700 MW of new renewable energy by 2036. This represents a total potential investment of approximately $9.5 billion. The company maintains its goal of 2,800 MW by 2030.
• Adding 800 MW of battery storage, including 400 MW by 2030 – five years earlier than previously planned – with an additional 400 MW of battery storage by 2035. This represents a total potential investment of $1.3 billion through 2035.
• Planning 1,200 MW of clean, on-demand generation to be ready to serve customers in 2040 and an additional 1,200 MW by 2043.

The projects include wind, solar and renewable natural gas facilities (RNG) as well as battery storage capacity.

Solar and wind projects announced this year are a mix of company-built and owned projects and power purchase agreements (PPAs).

Consumers Energy also worked with farmers to announce construction of multiple RNG facilities across the state following expansion of the utility’s MI Clean Air program. In many cases, RNG is considered carbon negative, as it captures and prevents more emissions than it emits.

Consumers Energy’s clean energy goals include bringing 8,000 MW of solar online by 2040 and achieving net-zero carbon emissions from its electric generation and distribution systems.

The Michigan utility’s Clean Energy Plan also calls for eliminating coal as an energy source in 2025 and meeting 90 percent of customers’ energy needs through clean sources.

The American Electric Power (AEP) subsidiary has proposed adding a 450-Megawatt (MW) natural gas plant to be located at the previously retired H.W. Pirkey Power Plant site in Hallsville, Texas. The new Hallsville plant is expected to come online in 2027, pending approval from utility regulators in Arkansas, Louisiana and Texas. According to regulatory filings submitted December 17, the facility would feature two GE combustion gas turbine generators and utilize existing water intake structures and site infrastructure to minimize project costs, SWEPCO said.

The utility is also planning a coal-to-gas conversion project at the Welsh Power Plant, located northwest of Cason, Texas. The 1,053 MW project would convert the existing coal-fired boilers of Units 1 and 3 to burn natural gas, with Unit 1 conversion anticipated in 2028 and Unit 3 in 2027.

Natural gas currently accounts for 48% of SWEPCO’s existing power generation portfolio. Due to the evolving reserve requirements set by the Southwest Power Pool, SWEPCO anticipates an increasing capacity need.

In addition to the projects mentioned above, SWEPCO has selected a short-term capacity agreement with a natural gas-fired plant in Texas as part of a competitive bid process. The company said this agreement would serve as a bridge to more permanent resource additions.

SWEPCO continues construction on multiple renewable energy projects. The largest one, the 598 MW Wagon Wheel Wind Facility, spans five counties in Oklahoma and is expected to be operational in December 2025.

The 200 MW Diversion Wind Farm, located in Baylor County, Texas, is scheduled to begin operations this month.

SWEPCO’s first utility-scale solar farm, the 72.5 MW Rocking R Solar Facility, is also nearing completion in Caddo Parish, Louisiana. SWEPCO will not own the facility and will instead purchase the electricity generated via a purchase power agreement.

If Virginia Gov. Glenn Youngkin and Democratic leaders in the General Assembly are aligned on one thing, it’s their enthusiasm for bringing more data centers to the commonwealth. Where they part ways is in how to provide enough electricity to power them. Youngkin and most Republican legislators advocate for an “all of the above” approach that includes fossil gas as well as renewables; Democrats are committed to staying the course on the transition to zero-carbon energy, with a near-term emphasis on low-cost solar. 

Data centers are making the transition harder, but so is local resistance to building solar. General Assembly members mostly understand the connection, leading to a lively debate in last year’s legislative session over whether to override some local permit denials for solar projects – and if so, how to ensure the localities still have some say. Though none of the legislative proposals moved forward last year, the topic has become a central one for the recently revamped Committee on Electric Utility Regulation (CEUR). 

In January, the General Assembly is likely to consider legislation to override local solar permit denials in some cases, such as last year’s HB636 from Del. Rip Sullivan, D-Fairfax, or another approach that would break the solar logjam. It remains to be seen, however,  whether legislators will take any action on data centers.

The problem has grown only more urgent as localities have continued to approve new data center proposals with little thought given to where and how they will get the power to serve them.

Ann Bennett, Sierra Club Virginia’s data center chair, has been tracking data center permit applications across the state. She counts at least two dozen Virginia counties with data centers under development, including rural areas far outside the industry’s stronghold in suburban Northern Virginia. By Bennett’s calculation, data centers existing and under development in Virginia will consume at least 100,000 acres. 

Even as local governments woo data centers, many have become hostile to solar development. A presentation from the Weldon Cooper Center at the University of Virginia, which tracks solar permitting across Virginia, shows that far more local permits for solar facilities have been denied or withdrawn than were approved this year. 

In some cases, county boards that approve data center development also reject permits for solar farms. Sometimes, it happens even at the same meeting.

In an effort to understand this paradox, I watched footage from two county board meetings in Hanover County, one in March of this year and the other in September. At the March meeting, county supervisors approved a 1,200-acre data center complex for an area north of Ashland. Later the same night, they denied a permit for a utility-scale solar project. 

The parcels of land slated to be developed for the data center complex “included wooded areas, recently-logged areas, open fields, wetlands, ponds and stream corridors.” The developer plans to build about 30 data centers on the property, each 110 feet tall (about 10 stories), with setbacks from the property line ranging from 150 to 250 feet. The complex will require 700,000 gallons per day of cooling water. When fully developed, the data centers are expected to total a staggering 2,400 megawatts (MW) of power capacity, not far short of what all of Loudoun County had in 2022. There was no discussion of where so much electricity would come from. 

Public testimony was overwhelmingly negative. The objections echoed those that have been widely reported in response to projects such as the Prince William Digital Gateway: noise, light, a massive increase in truck traffic, secrecy surrounding the project, air pollution from diesel back-up generators. 

Yet the Hanover supervisors voted unanimously in favor of the project. It came down to money: the developer promised a tax benefit to the county over 20 years of $1.8 billion, plus upfront cash for road improvements and a $100,000 donation to a park. Supervisor Jeff Stoneman, who represents the Beaverdam district where the complex will be located, acknowledged his constituents’ concerns but noted that the revenue would be a “game-changer for this community.” 

Even for me, as thoroughly aware as I am of all the downsides of data center sprawl, the negative impacts on communities, the risks to our water and energy security, the possibility that folks will be left with nothing but regrets – well, I just have to say: It’s really hard to argue with $1.8 billion. Rural leaders see Loudoun County raking in revenue from data centers, letting it cut taxes for everyone else. Why wouldn’t they want in on that?

As I noted before, though, there was no discussion of how or where the enormous amount of electricity needed to power the data centers would be generated. This disconnect was underscored later in the same meeting when the supervisors voted to reject a 20 MW solar project on 100 acres of a 315-acre site, in the same district as the data center complex they had just approved. 

It was especially hard to understand the denial of this particular permit. Supervisors agreed the project met all the terms of the county’s solar ordinance, including provisions for the use of native grasses and pollinator plants. Most of the property would remain untouched. The county would receive an upfront cash contribution of $438,600, in addition to the increased tax revenue from the project. The planning commission had recommended approval. No one testified against it; a number of people, including the farmer across the street, testified in its favor.  

Most of the discussion of the project focused on screening the solar panels from view. Supervisors fussed that the trees to be planted at the entrance were too small, and worried that some of the existing mature trees along the road might die off over time and not be replaced. The developer agreed to put larger trees at the entrance, and even to walk the perimeter annually to monitor the health of the trees, and replace any if they needed to.

It was no use. Two of the supervisors wanted to approve the project, but they were outvoted. Stoneman, the Beaverdam supervisor who had led the way in supporting the data center complex, said he worried that erosion might impair the creek on the property, in spite of ample natural buffers, and said he did not have a “comfort level” with the project.

Evidently, the county’s solar ordinance, adopted in 2023, was irrelevant, or at least, misleading. Such objective standards make a developer think it will be worth their while to put in months of planning, public outreach, and working with county staff. But then it turns out that what actually matters is whether a supervisor can achieve a certain undefined “comfort level.” 

Six months after the approval of the 2,400 MW data center complex and the denial of the 20 MW solar facility, another solar project met the same fate, again with Stoneman making the motion to deny the permit. 

This time the project would take up 250 acres of a 1,500-acre site and produce 72 MW of electricity, achieved through stacking the panels to a double height. Again, the project more than met the requirements of the county solar ordinance. The land was described as currently consisting of managed pine forest, already subject to being cut over at any time, and fully 70% of the property would be preserved for conservation. Native grasses would be planted, and sheep would do most of the vegetation management. The shepherd, Marcus Gray of Gray’s Lambscaping, attended the hearing to describe the sheep operations he runs successfully at other solar sites.  

Approval of the project would earn the county roughly $1.7 million upfront, and $300,000 in annual tax revenue. 

Supervisors praised the developer for “a really good application” that “respected” the ordinance and the environment, for the company’s willingness to listen and respond to concerns, and for agreeing to build stormwater basins and sacrifice buildable space in favor of conservation. 

Several members of the public testified in favor of the project, but this time there were also opponents. Some of them repeated common myths about solar panel toxicity and the risk of fires. One woman stated flatly, and obviously incorrectly, that it was not possible to raise sheep at a solar farm because they would die from the heat. 

The supervisors themselves did not appear ill-informed or misinformed, though one expressed surprise that Gray could successfully sell his lamb at farmers markets when buyers knew where they had been raised. (Watching, I could only laugh, because I’ve always thought of the solar-sheep synergy as a great selling point for climate-conscious carnivores.) 

The concern raised most often was the risk of impacts to the nearby North Anna River, though the developer had agreed to shrink the project to accommodate a much greater setback from the river than required. 

Ultimately, however, Supervisor Stoneman’s argument for denying the permit rested on a different argument. He praised the developer for doing a good job, and noted the project was in accordance with all requirements. But, he said, “Beaverdam is just a different place.” People take pride in the rural character and forest and farmland. Our job, he noted, is to protect the trees that are harvested on the site currently, something “that is as important as the power.” 

“Money is not the most important thing,” concluded the man who led the cheering squad for a data center complex in his district six months earlier.  

The two supervisors who had supported the smaller solar facility that had been rejected in March made their best arguments for this project as well, though they ultimately voted with Stoneman as the home supervisor. One said she supported solar “because I’m pro-farm,” and solar is a way to preserve farmland from development. The other noted that the land would certainly be developed one way or another, and the results would almost certainly be worse. Maintaining rural culture is important, he noted, but “we are approving residential development and seeing by-right development that people don’t want either.”

He also warned his colleagues, as he had in the spring, that rejecting good solar projects was going to result in legislation that would take away local authority and give it to the unelected State Corporation Commission. He said he would go along with Stoneman’s motion to deny the permit because “I assume he knows something,” but he made it clear he considered it the wrong decision, and a dangerous one for local autonomy.

Evidently, he had been paying attention to the conversation at the General Assembly.

To be clear, my sympathies lie wholeheartedly with people whose instincts are to protect the woods and fields around them. I share the one Hanover supervisor’s belief that solar is a means to preserve land from permanent development and even improve soil health and wildlife habitat, but I also understand it may be years before some people see sheep grazing under solar panels as a welcome feature in their landscape. 

So I get how a rural county, having sold a little bit of its soul for $1.8 billion, might then slam the door to other development, even after applicants had worked with the county for months in good faith and done everything asked for. 

It’s not a choice I’d make – I’d take solar over data centers every time – but then, no one made it the county’s responsibility to contribute electricity to the grid that serves it, much less to produce the electricity needed to run the data centers it embraced.

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

In a filing sent to the North Carolina Utilities Commission (NCUC) last week, Duke said it will pause “any further efforts or expenditures” until February, hoping to gain more clarity on the situation once the dust clears. The utility said it is “closely monitoring” the potential for changes to DOE’s Loan Programs Office (LPO) or to funding for loan guarantee programs under the IRA, which could impact the EIR Program.

In 2023, Duke, the NCUC Public Staff, Walmart, and the Carolinas Clean Energy Buyers Association (CCEBA) entered into an agreement to further assess the cost and benefits of the EIR program. Under this agreement, the parties agreed to hire a consultant to refine the cost-benefit analysis of the EIR program to assess the potential to achieve ratepayer benefits, Duke said. A report stemming from the consultant’s work was meant to be filed with the NCUC by May 1, 2025.

However, the companies and NCUC Public Staff have not selected a consultant yet after sending multiple RFPs to several companies in October. Given Duke’s decision to halt the process, it notified the NCUC that it would likely not meet the May 1 deadline for the consultant’s report.

Through the Energy Infrastructure Reinvestment (EIR) category of the Title 17 Clean Energy Financing Program, LPO can finance projects that retool, repower, repurpose, or replace energy infrastructure that has ceased operations or enable operating energy infrastructure to avoid, reduce, utilize or sequester air pollutants or greenhouse gas emissions.

The EIR project category can support a range of projects that utilize existing energy infrastructure, including: 

• Upgrading or uprating energy infrastructure so it can restart or operate more efficiently, at higher output, or with lower emissions
• Replacing retired energy infrastructure with clean energy infrastructure
• Building new facilities for clean energy purposes that utilize legacy energy infrastructure

The U.S. energy sector as a whole is facing uncertainty after Trump’s re-election. On the campaign trail, President-elect Donald Trump railed against clean energy policies enacted under the Biden-Harris administration, vowed to throttle offshore wind development “on day one” and end the “Green New Scam.”  It’s still unclear if Trump will attempt to dismantle the landmark Inflation Reduction Act, which pumped billions into clean energy technologies like solar panel and electric vehicle manufacturing, investments that have largely benefited Republican-led communities.

Leading up to the election, Trump insisted the IRA was too expensive and promised to rescind all unspent funds allocated by the law- prompting the Biden administration to speed up to ensure it spends the majority of available grant funding left. Since parts of the IRA have not yet been fully implemented and it’s not clear which direction some of Trump’s incoming staff will be compelled to go in specific cases, its fate in totality remains murky.

Transmission advocates could potentially benefit from Trump’s desire to fast-track permitting for oil and gas pipelines, but that may not come in the form of the long-awaited energy permitting reform bill that passed the Senate in July. While a bipartisan effort, the bill has been stuck in the Republican-controlled House, and some large utilities are reportedly lobbying lawmakers to stop it.

Originally published in POWERGRID International.

Georgia Power projects that over the next decade the state will be leading the nation’s second industrial revolution, led by artificial intelligence boosting data centers, which could triple the state’s energy consumption.

According to Georgia Power’s projections, the company’s projected 12,000 megawatts load growth will triple by the mid-2030, which is consistent with the state’s consistently upward trending economic prospects the company cites as it requests a significant expansion of its energy capacity.

“The latest data continue to support Georgia Power’s expectation for continued and robust economic growth in Georgia and the timing of new large loads,” the company’s Nov. 18 economic development outlook reads. “The pipeline of committed and potential economic development projects continues to grow.”

The Georgia Public Service Commission is scheduled to vote by next 2025 on the company’s long-term plans. The five-member board regulates the state’s utilities and will determine whether new natural gas plants will be built, if more solar power capacity is added, and how much more electricity customers will be charged when the company passes along rising costs.

Georgia Power is estimating that about 90 large-sized industrial projects could be built in Georgia before the end of the decade. Georgia Power has received commitments to purchase its electricity from about 70 prospective data center facilities should they be built inside the Peach State.

However, clean energy advocates are among the knowledgeable critics expressing skepticism about Georgia Power’s projected list of commitments from large data centers, questioning the accuracy of energy demand forecasts over the next several years and what the company says are actual energy usage levels by new data centers.

Georgia Power is set to outline its proposals to meet projected energy demand in its 2025 integrated resource plan, a three-year operations forecast due to be filed in late January with the Georgia PSC. The filing will kick start a process of hearings before state regulators and interested parties where expert testimony from Georgia Power and advocates for consumers and environmental protection are typically presented to chart the utility company’s energy future.

As of Sep. 30, Georgia Power says the total pipeline of economic development projects expected through the mid-2030s has increased by 12,200 megawatts to 36,500 megawatts, with large-scale facilities accounting for 34,600 megawatts. All 25 of the committed large scale projects are expected to be in service by the end of 2028 or sooner, the utility company’s quarterly report states.

“Thirteen of these projects have broken ground, and twelve are pending construction,” the report said. “This evidence clearly indicates that these large load customers are materializing and making progress without material delays.”

According to the U.S. Department of Energy data, centers consume 10 to 50 times as much electricity as the average commercial building.

A 2024 report from the Barclays Equity Research team estimates that data centers account for 3.5% of U.S. electricity consumption today, and the electricity use of those facilities could be above 5.5% in 2027 and more than 9% by 2035.

Maggie Shober, the research director at the Southern Alliance for Clean Energy, said she has concerns about the level of commitment Georgia Power is securing from the planned new data centers. Companies are committing to use Georgia Power as their electricity provider, but it does not guarantee they will build a data center in the state.

“Although these are scary numbers, I think there’s a lot of speculation going on, especially in the data center industry, where people and companies that are interested in sort of flipping sites for data centers are absolutely scrambling to get into this queue. I think that a lot of these will ultimately never show up. I think it’s going to be a challenge to figure out which ones and how do we determine that?”

After decades of almost non-existent demand growth for electricity in the U.S., the artificial intelligence revolution is expected to more than double data center electricity needs by 2030 based on current grid capacity, according to the Barclays report.

“Unlike other industries or energy-consuming activities which place fluctuating requirements on the grid depending on the time of day or year that can be managed to maintain overall reliability and capacity, AI operations are an ‘always on’ demand,” Barclays senior research analysts Will Thompson and Betty Jiang wrote in the August report. “Data centres must operate continuously, 24/7/365, to function for users. In effect, AI energy demand can be considered a constant peak that leads to higher overall peak power demand across the grid.

“With the current focus on building data centre capacity that prioritises secure access to power over specific fuel type, meeting rising electricity demand while lowering emissions will likely be a monumental challenge for grid operators,” the Barclays report said.

In April, the Georgia Public Service Commission approved Georgia Power’s plans to expand its generation capacity by increasing its reliance on fossil fuels and adding more renewable energy by 2025. The company’s integrated resource plan will be the next significant development since then.

Georgia Power is projecting the updated plans will save the typical residential customer about $2.89 on their monthly bills from 2026 to 2028.

“At Georgia Power, our customers are at the center of everything we do, and we are unwavering in our commitment to provide them with clean, safe, reliable and affordable energy,” Georgia Power CFO Aaron Abramovitz said in April.

State regulators already approved the company’s request for natural gas or oil-burning generators and solar batteries to meet increasing demand from data centers and other large industrial users over the next decade. Regulators were warned by several clean energy groups against allowing Georgia Power to build three fossil fuel burning units at the legacy fossil-fuel facility Plant Yates in Coweta County.

Concerns linger for clean energy advocates like the Southern Environmental Law Center, anxious about what the upcoming request from Georgia Power will mean for the state’s energy future. The company has also been given the green light by state regulators to delay the retirement of its coal-burning plants Bowen in Bartow County and Scherer in Monroe County.

If Georgia Power’s projected electricity demands fall short, the company would still reap the financial benefits of adding new energy sources, said Jennifer Whitfield, SELC senior attorney.

“If you’re over projecting, and you don’t actually need to meet those demands, it’s not the Georgia Power shareholders who are going to pay for that,” Whitfield said. “ It’s going to be Georgia Power customers.

“That is a particular concern for overbuilding gas plants, because the cost of gas plants is for the fuel, and those costs get passed on directly to customers,” Whitfield said. “George Power customers, in particular, have seen a bunch of increases. They’ve had a rate increase. They’ve had Plant Vogtle increases. The largest increase they’ve seen in the last few years is actually from fuel costs.”

The Barclays research report found that sustainability appears to be a lower priority for the majority of data center companies.

“Data centre developers are prioritising land with access to untapped power sources, water, workforces and favourable regulation,” the report says. “With the current focus on building data centre capacity that prioritises secure access to power over specific fuel type, meeting rising electricity demand while lowering emissions will likely be a monumental challenge for grid operators,” the report says.

Whitfield said the commission has some ability to be creative with how it requires Georgia’s Power to diversify its sustainable energy portfolio. The company’s plans include some positives, she said, such as expanding solar and programs that benefit seniors living on fixed incomes.

“Is this going to be this moment where we decide, as Georgians, who we want to be? What kind of energy future do we want to have?” Whitfield said.

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

Solar continues to grow the fastest in the U.S. During the first nine months of 2024, utility-scale solar power generation (thermal and PV) output increased a whopping 30.1% from the same period in 2023. Estimated total solar from all facilities (utility- and smaller-scale) increased 25.1% during this same period.

In the month of September 2024 alone, utility-scale solar (thermal and PV) increased 29% from the month of September 2023.

Significant installations are driving the increase in solar generation, with solar accounting for 59% of U.S. generating capacity additions in the first half of 2024, EIA reported in September. The increase in solar capacity was also supported by the development of new battery storage capacity, the agency said.

Unsurprisingly, Texas and California were on track to receive the largest gains in solar generation this year: 16 billion kilowatthours (BkWh) for the former, and 9 BkWh for the latter, per EIA.

Through September 2024, utility-scale wind generation increased 6.6% over the same nine-month period in 2023.

Generation from all renewable energy sources, excluding hydroelectric, increased 12.2% in the 2024 nine-month period.

Renewable energy developer, owner, and operator Arevon Energy has started commercial operations at its $529 million Vikings Solar-plus-Storage Project in Imperial County, California, believed to be the first utility-scale solar peaker plant in the United States. Its very existence contradicts the notion that renewable energy is inherently unreliable, instead providing carbon-free electricity at specific times of critical need to support the grid and empower ratepayers.

The specs

Vikings will utilize a 157 megawatt (MW) solar array paired with 150 MW/600 MWh of battery energy storage to shift low-cost daytime solar energy to higher-cost peak demand periods, lowering the cost of electricity for nearly one million customers of San Diego Community Power, the project’s offtaker. The companies have also executed a commercial agreement for Arevon’s 200 MW Avocet Energy Storage Project located in the City of Carson, California, which is expected to start construction in early 2025.

Vikings’ battery storage system can rapidly adjust capacity in seconds to address changes in demand. The project features key components from domestic manufacturers, leveraging incentives provided by the Inflation Reduction Act to maximize value. They include Megapack battery energy storage systems manufactured by Tesla in Lathrop, CA, First Solar thin-film photovoltaic solar panels, and Nextracker smart solar trackers. San Diego-headquartered SOLV Energy led the engineering, procurement, and construction (EPC).

“Vikings’ advanced design sets the standard for safe and reliable solar-plus-storage configurations,” said Kevin Smith, Arevon’s chief executive officer at last week’s ribbon cutting. “Its completion marks a significant milestone for Arevon.”

Typically, hybrid projects serve load when the sun is up and store the excess generation in their battery. That energy is then discharged in the evening during peak demand.

“The unique 1:1 solar to storage configuration of Vikings allows the project to shift the entirety of its generation from ‘solar hours’ to the peak demand period,” explains Jacob Montgomery, director of development at Arevon. “As an industry, we have already made steps in energy shifting a portion of solar generation by coupling solar with storage. The Vikings project takes it one step further by shifting the full output of the facility. This is another step in the right direction to provide clean renewable energy around the clock.”

Vikings, located near Holtsville, CA, was named after the local high school’s mascot and provided scholarships for several Holtsville H.S. students to use for college tuition costs. The project employed more than 170 personnel during its construction and will disburse more than $17 million to local governments over its lifespan, providing revenue for schools, first responders, and other community needs.

Vikings was previously recognized with the IJGlobal’s Renewables Deal of the Year – Energy Storage Award, lauded as one of the first utility-scale solar-plus-storage ITC and PTC transfer agreements since the U.S. Treasury announced the guidance for tax transferability in June of 2023. The project was financed with a $228M construction facility and a $72M ITC transfer bridge loan facility. In the past 12 months, Arevon has completed project financings of more than $3 billion.

Arevon’s endeavors

Arevon Energy, headquartered in Scottsdale, Arizona, owns and operates more than 4,000 MW of utility-scale solar, energy storage, and solar-plus-storage projects as well as distributed generation assets in 17 states. The company is constructing more than 2,000 MW of new solar and storage capacity and has a development portfolio of more than 6 gigawatts.

In July, Arevon started operations at its 200 MW/800 MWh Condor Energy Storage Project in San Bernardino County, California, its third utility-scale storage site in the state. Arevon also recently secured offtake agreements for its Cormorant Energy Storage Project and its Avocet Energy Storage Project and closed financing on its Eland 2 Solar-plus-Storage Project, its Condor Energy Storage Project, and the Vikings project.

Arevon’s chief operating officer Justin Johnson, who oversees EPC operations, says developing relationships with offtakers is similar to doing so with equipment suppliers, construction firms, and O&M service providers.

“We do a deal with them, we build a project, and we deliver what we promised when we promised. They’re comfortable with us, they trust us and you can do repeat business with them,” he explains. “It’s the same thing with the communities too. You build a project in the community, you’re a good member of the community, you support charity, you pay your property taxes… And then they see that it’s not so bad living next to a solar plant.”

Originally published in Renewable Energy World.

Due to an “unprecedented increase” in projected customer demand seen in its fall load growth forecast, Duke Energy provided state regulators with supplemental modeling on Jan. 31, 2024.

In July this year, prior to the NCUC’s evidentiary hearing on the plan, Duke Energy, the NCUC Public Staff, Walmart and the Carolinas Clean Energy Business Association reached a broad settlement on most topics at issue in the Carolinas long-range plan. The settlement committed Duke Energy to increasing the amount of solar energy and battery storage on its system through 2030, provided the opportunity to upgrade existing small solar facilities that are approaching the end of their contract terms with Duke, and committed Duke Energy to continued reform of its transmission planning process.

Duke Energy originally filed its proposed Carolinas Resource Plan with the North Carolina Utilities Commission (NCUC) On Aug. 17, 2023, two days after filing the same plan with the Public Service Commission of South Carolina (PSCSC). The Carolinas Resource Plan is Duke Energy’s proposed road map for its dual-state system serving North Carolina and South Carolina.

“We believe this is a constructive outcome that allows us to deploy increasingly clean energy resources at a pace that protects affordability and reliability for our customers,” Duke Energy said in a statement. “The order confirms the importance of a diverse, ‘all of the above’ approach that is essential for long-term resource planning and helps us meet the energy needs of our region’s growing economy. We look forward to thoroughly reviewing the NCUC order and incorporating it into our future resource planning.”

After gathering input from public hearings, evaluating Duke’s proposal, modeling, and settlement – along with modeling from Public Staff and targeted recommendations from intervenors – and conducting an extensive evidentiary hearing across two weeks, the NCUC issued its decision late last week. The order accepts the July settlement in its entirety.

Specifically, the order directs Duke Energy to pursue the following:

Near-Term Resources

• Solar: 3,460 megawatts (MW) of new solar generation, beyond the NCUC’s 2022 order – 6,700 MW total by 2031.
• Battery: 1,100 MW of battery energy storage, beyond the NCUC’s 2022 order – 2,700 MW total by 2031.
• Onshore Wind: 1,200 MW of onshore wind in operation by 2033, including at least 300 MW in operation by 2031.
• Combustion Turbines (CTs): Four CTs by 2030 – 900 MW of additional CTs (two units) beyond the 800 MW (two units) in the NCUC’s 2022 order.
• Combined Cycles (CCs): Three CC units by 2031 – 2,720 MW of additional CC capacity (CC2 and CC3) beyond the 1,200 MW (CC1) in the NCUC’s 2022 order.

Long-Term Resources

• Bad Creek II: Approved continued development work, including requested $165 million in early development costs.
• Nuclear: Approved continued development work, including requested $440 million in early development costs, targeting 300 MW of advanced nuclear capacity on line by 2034 and a total of 600 MW by 2035.
• Offshore Wind: Approved continued development work through the Acquisition Request for Information (ARFI) to advance the evaluation of offshore wind’s role in future resource plans, with results filed no later than July 30, 2025, and targeting between 800 and 1,100 MW of offshore wind by 2034 and 2,200 to 2,400 MW by 2035.

Modeling, Reserve Margin, Interim Carbon Reduction Target and Other Key Findings

• Confirmed Duke Energy’s recommended portfolio, P3 Fall Base, as the “reference portfolio.”
• Approved increase in the minimum planning reserve margin to 22% by 2031.
• Waived the requirement to model 70% carbon reduction by 2030, agreed that the evidence in the case supported the decision to extend the date for achieving 70% carbon reduction beyond 2032, and ordered Duke Energy to continue pursuing “all reasonable steps” to achieve 70% carbon reduction by the earliest possible date.
• Confirmed proposed coal retirement dates.
• Noted that “The Commission must be mindful of the impacts to customers when determining the appropriate action to take … to ensure that Duke, and North Carolina, continue this trajectory of rates that are at or below the national average,” highlighting the inflation-adjusted bill impact of the plan as a 0.9% increase by 2038.

The PSCSC continues to deliberate on the resource plan and will issue an order on or before Nov. 26, 2024. Following that order, Duke Energy said it will begin executing the plan while simultaneously developing the modeling required for its 2025 plan update in North Carolina, which must be filed by September 2025. As outlined in North Carolina law, the plan must be checked and adjusted every two years, incorporating technology advances, updated cost forecasts and applicable federal funding that could help customers save money over time.

In it’s 2024 filing to the NCUC, Duke said “new economic development wins, including manufacturing and technology projects across the Carolinas” make up the primary driver of the increased electric demand. The utility said annual demand expects to increase 22% by 2030 and 25% by 2035 from 2022 planning cycles — driven by significant additional economic development activity that took place during 2023. Notably, according to the Census Bureau, South Carolina’s population grew faster than any state’s in 2023.

Duke Energy put forth its original resource plan to regulators in August 2023. The company presented three portfolio scenarios but recommended one that achieves 70% CO2 emission reductions from 2005 levels by 2035. The “Portfolio P3 Fall Base,” introduced almost 6.8 GW of additional resources.

This strategic partnership combines KKR’s experiences in digital infrastructure, power and the energy value chain with ECP’s energy transition platform in electrification and power and renewable generation.

The strategic partnership is intended to deliver scaled data center and power solutions for hyperscalers and other market participants to support their infrastructure needs across geographies to drive model training, tuning, and inferencing at scale. KKR and ECP plan to engage with industry leaders including utilities, power and data center developers, and independent power producers to accelerate the delivery of data center campuses required by hyperscalers.

KKR is funding the strategic partnership from existing infrastructure and real estate strategies and insurance accounts managed by the firm. ECP is funding the strategic partnership from existing and future infrastructure capital pools.

“Data center power demand is expected to grow by 160% by 2030, a demand that will go unmet without the right infrastructure in place, which is critical to boosting productivity, supporting electrification and helping countries create a competitive edge in AI,” said Joe Bae, Co-Chief Executive Officer, KKR.

To date, KKR has invested more than $29 billion across 22 investments in relevant digital infrastructure companies across data centers and fiber, as well as $15 billion in power, utilities and energy. KKR’s global data center footprint spans four platforms with several GW of deployed assets across over 100 facilities and more under development globally. KKR’s portfolio also includes over 10 renewable energy developers with over 50 GW of global development pipeline.

ECP has owned, controlled, and operated over 83 GW of power generation across all major U.S. power markets, spanning a variety of technologies including natural gas, geothermal, hydro, solar, wind, battery storage and waste-to-energy since its founding in 2005. ECP is also the majority owner of an aeroderivative power turbine platform and manufacturer, ProEnergy, which the companies say will provide an important link in accelerating the delivery of electricity to data center projects.

After years of flat load growth on the U.S. grid, electricity demand is rising due to numerous factors – notably industrial onshoring, widespread electrification and the adoption of AI data centers.

According to a recent EPRI white paper, electricity usage by hyperscalers more than doubled between 2017 and 2021. This increase is expected to continue, with data centers projected to consume 5% to 9% of U.S. electricity generation annually by 2030, up from 4% today. Demand for computing power from data centers, fueled by artificial intelligence and other new technologies, requires enormous amounts of power. 

In the U.S., data center demand is expected to reach 35 GW by 2030, up from 17 GW in 2022, McKinsey & Company projects. 

According to EPRI, 15 states accounted for 80% of data center capacity in 2023, led by Virginia, Texas, California, Illinois, Oregon, and Arizona. That concentration creates economic opportunities for states hosting data centers, but could also stress the grid.