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.

A major expansion of battery storage may be the most economical and environmentally beneficial way for Illinois to maintain grid reliability as it phases out fossil fuel generation, a new study finds.

The analysis was commissioned by the nonprofit Clean Grid Alliance and solar organizations as state lawmakers consider proposed incentives for private developers to build battery storage.

“The outlook is not great for bringing on major amounts of new capacity to replace the retiring capacity,” said Mark Pruitt, former head of the Illinois Power Agency and author of the study, which suggests batteries will be a more realistic path forward than a massive buildout of new generation and transmission infrastructure. 

The proposed legislation — SB 3959 and HB 5856 — would require the Illinois Power Agency to procure energy storage capacity for deployment by utilities ComEd and Ameren. Payments would be based on the difference between energy market prices and the costs of charging batteries off-peak, to ensure the storage would be profitable. The need for incentives would theoretically ratchet down over time. 

“As market prices for power go up, your incentive goes down,” Pruit said. “The idea is to provide an incentive that bridges the gap between the cost of battery technology and the value in the market. Over time, those will equalize and level out.” 

The bills, introduced in May at the end of the legislature’s spring session, would amend existing energy law to add energy storage incentives to state policy, along with existing incentives for nuclear and renewables. 

The study noted that Illinois will need at least 8,500 new megawatts of capacity and possibly as much as 15,000 new megawatts between 2030 and 2049, with increased demand driven in part by the growth of data centers. Twenty-five data centers being proposed in Illinois would use as much energy as the state’s five nuclear plants generate, according to nuclear plant owner Exelon’s CEO Calvin Butler Jr., quoted by Bloomberg. 

The North American Electric Reliability Corporation (NERC) found in its summer and winter 2024 assessments that within MISO and PJM regional grids, Wisconsin, Michigan, Minnesota, Illinois and Indiana are all at “elevated” risk of insufficient capacity. 

“NERC, PJM, MISO and the Illinois Commerce Commission have all identified the potential for capacity shortfalls,” said Pruitt. “You do have some options for alleviating that. You can build transmission and bring in capacity from outside the state. You can maintain your current domestic generating capacity [without retiring fossil fuel plants]. You could expand your domestic generating capacity. And an independent variable is your growth rate. All these have to work together, there’s no silver bullet. We know there are major challenges on each of those fronts.” 

Gloomy numbers 

The latest PJM capacity auction results showed capacity prices increasing from $28.92/MW-Day for the 2024/25 period to $269.92/MW-Day — a nearly 10-fold increase — for the following year. That “translates into an annual cost increase of about $350 for a typical single-family household served by ComEd,” Pruitt said. “The increase in costs indicates that more capacity supply is required to meet capacity demand in the future.” 

There are many new generation projects in the queue for interconnection by MISO and PJM, but many of them drop out before ever being deployed because of unviable economics, long delays, regulatory challenges and other issues. A recent study by Lawrence Berkeley National Laboratory noted that while interconnection requests for renewables have skyrocketed since the Inflation Reduction Act, only 15% of interconnected capacity was actually completed in PJM and MISO between 2000 and 2018, and experts say similar completion rates persist. 

“This finding indicates that deploying sufficient new capacity resources to offset [fossil fuel] retirements is not likely to occur in the near term,” said Pruitt. “Just because something is planned doesn’t mean it gets built.” 

Meanwhile the state is running out of funds for the purchase of renewable energy credits (RECs) that are crucial to driving wind and solar development. The 2024 long-term renewable resources procurement plan by the IPA shows the state’s fund for renewables reaching a deficit in 2028, so that spending on RECs from renewables will have to be scaled back by as much as 60%. 

Long-distance transmission lines could bring wind energy or other electricity from out of state. But planned transmission lines have faced hurdles. The Grain Belt Express transmission line, in the works for a decade, was in August denied needed approval from an Illinois appellate court. The transmission line, proposed by Invenergy, would have brought wind power from Kansas to load centers to the east. 

“That sets it back years,” Pruitt said. “Transmission is a very long-term solution. I’m sure people are working diligently on it, but it’s five to 10 years before you get something approved and built.” 

Value proposition, solar benefits 

Pruitt’s study found that if 8,500 MW of energy storage were deployed between 2030 and 2049, Illinois customers could see up to $3 billion in savings compared to if they had to foot the bill for increased capacity without new storage. The savings would come because of lower market prices in capacity auctions, as well as investment in new transmission and generation that would be avoided. 

Pruitt found that $11 billion to $28 billion in macro-level economic benefits could also result, with blackouts avoided, reduced fossil fuel emissions and jobs and economic stimulus created. 

Pruitt’s analysis indicates that the incentives proposed in the legislation would cost $6.4 billion to customers. But the storage would result in $9.4 billion in savings compared to the status quo, hence a $3 billion overall savings between 2030 and 2049. 

“Solar is great, but solar is an intermittent resource; battery storage when paired with solar allows it to be far more reliable,” said Andrew Linhares, Central Region senior manager for the Solar Energy Industry Association. “Battery storage is not as cheap as solar, but its reliability is its hallmark. Combining the resources gives you a cheap and reliable resource.” 

“Solar and storage is this powerful tool that can help reduce costs for consumers and create new jobs and economic activity,” he continued. “I don’t believe that same picture is there for building out new natural gas resources. Anything that helps storage, helps solar and vice versa. CEJA sees these two technologies as being joined at the hip for the future, they are being seen more and more as a single resource.”

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

Houston-based geothermal startup Sage Geosystems and the artist formerly known as Facebook, Meta Platforms, have announced a new agreement to deliver up to 150 MW of new geothermal baseload power to support the latter’s data center growth. The deal would be the first use of next-generation geothermal power east of the Rocky Mountains, the companies said, without revealing its precise location. The first phase of the project is expected to be operational in 2027.

The U.S. has geothermal power plants in seven states, which generated about 16.46 terawatt hours (TWh) of geothermal electricity in 2023, a .5 TWh increase from 2022 and the highest amount ever recorded. That accounted for about 0.4% (17 billion KWh) of total U.S. utility-scale electricity generation last year.

The United States boasts roughly 3,900 MW of installed geothermal, about one-quarter of the world’s total capacity. Most of it is in California (66.6% of 2023 total U.S. geothermal generation) and Nevada (26.1%), with smaller concentrations of development in Utah (3.2%), Hawai’i (2.1%), Oregon (1.3%), Idaho (.5%), and New Mexico (.2%).

The U.S. Department of Energy (DOE) sees tremendous potential for geothermal development, suggesting there may be more than 100 GW of capacity in the lower 48 states.

Fittingly, the new announcement was made at the DOE’s Catalyzing Next Generation Geothermal Development Workshop. Executives from Sage and Meta joined U.S. Deputy Secretary of Energy David Turk and additional Biden-Harris Administration officials along with, investors, utilities, and other energy stakeholders to discuss the opportunity and growth of geothermal.

“The U.S. has seen unprecedented growth in demand for energy as our economy grows… And new industries like AI expand,” said U.S. Energy Deputy Secretary David Turk. “The Administration views this increased demand as a huge opportunity to add more clean, firm power to the grid and geothermal energy is a game-changer as we work to grow our clean power supply.”

“This announcement is the perfect example of how the public and private sector can work together to make the clean energy transition a reality,” added Cindy Taff, CEO of Sage Geosystems. “We are thrilled to be at the forefront of the next generation of geothermal technology and applaud the DOE for supporting the commercialization of innovative solutions.”

Sage will utilize its proprietary Geopressured Geothermal System (GGS) to provide carbon-free power to Meta’s data centers. Sage says it validated the technology in the field in early 2022, which promises to harness geothermal energy almost anywhere. Hot dry rock is a vastly abundant resource compared to traditional hydrothermal formations, making Sage’s GGS technology more scalable than other approaches, the company says.

Sage previously announced the first geothermal project in Electric Reliability Council of Texas (ERCOT) territory, a unique 3-MW baseload power and energy storage system in partnership with San Miguel Electric Cooperative in Christine, Texas. That project is expected to begin operating later this year and is slated to be the first commercial-scale deployment of GGS, according to the company. It was financed by a $17 million round of Series A funding by fracking pioneer Chesapeake Energy earlier this year.

“Our EarthStore facility in Christine will be the first geothermal energy storage system to store potential energy deep in the earth and supply electrons to a power grid,” boasted Sage Geosystems CEO Cindy Taff.

Don’t forget about Fervo

Another Houston geothermal company is also making deals with companies hoping to fuel their data centers with renewable power. Fervo Energy, which raised $244M led by Devon Energy earlier this year, started working with Google in 2021 to develop next-generation geothermal power and has since launched projects sending power back to the Nevada grid to power its own data center operations.

Earlier this summer, Fervo signed a pair of 15-year power purchase agreements (PPAs) with Southern California Edison to provide up to 320 MW of electricity from Fervo’s 400 MW Cape Station project under construction in Beaver County, Utah. The first 70 MW phase of the project should be online by 2026, and it should reach capacity by 2028.

The race for RECs, PPAs, and EAPAs

Meanwhile, Meta and its contemporaries in the data center space are gobbling up renewable energy certificates (RECs) left and right.

Meta recently partnered with Arevon Energy on a third Environmental Attributes Purchase Agreement (EAPA) for Arevon’s Heirloom Solar in Pike County, Indiana.

This month, Google announced a 1.5 GWp solar development contract with Energix Renewables and closed on a tax equity investment with Swift Current Energy on the massive 800 MWdc Double Black Diamond project in southern Illinois.

Microsoft and Pivot Energy signed a five-year framework agreement to develop up to 500 megawatts (MWac) of community-scale solar energy projects across the United States between 2025 and 2029. In May, Microsoft inked two 15-year PPAs with developer RWE for two new onshore wind farms in Texas with a combined capacity of 446 MW and shook hands with Canada’s Brookfield Asset Management on the largest single corporate PPA ever, agreeing to develop more than 10.5 gigawatts of new renewable energy capacity.

According to BloombergNEF, Amazon was the most active company in the PPA space last year, purchasing more solar and wind power than the next three companies combined and announcing 74 PPAs totaling 8.8 GW of capacity. The other top PPA purchasers: Meta (3 GW), LyondellBasell Industries (1.3 GW), and Google (1 GW). 

Originally published in Renewable Energy World

Today New Mexico Commissioner of Public Lands Stephanie Garcia Richard executed a pair of long-term leases for projects on state lands. One was awarded to EDF Renewables to develop a wind energy project on 23,840 acres in Grant County; a second lease was awarded to Innergex Renewable Energy for a wind project on 12,192 acres in Hidalgo County.

When it’s finished, the EDF project is expected to generate around 400 MW of wind energy, making it the second-largest wind project on New Mexico state lands, trailing only Pattern Energy’s massive Western Spirit Wind, which has 1,050 MW of installed capacity encompassing four sites in Central New Mexico. Garcia Richard signed off on that project as well, in 2020.

Innergex’s new wind farm is expected to put out about 150 MW. Bids for each lease were unsealed at public auctions at the State Land Office building in Santa Fe, per Garcia Richard.

“We are continuing to help the renewable energy sector grow with each major wind or solar deal on state lands. The fact that there were multiple qualified bidders on both of these leases shows that companies are taking us seriously when we say we are open for business,” Commissioner Garcia Richard said. “New Mexico is blessed with plenty of wind and sun, as well as nine million acres of state lands, making us well-positioned to expand our renewable portfolio even more. These wind projects will provide real, long-term revenue to help make a difference in New Mexico’s classrooms.”

Commissioner Garcia Richard created the first-ever Office of Renewable Energy within the Commercial Resources Division at the State Land Office intending to triple renewable energy leasing and production on state trust lands. The Office has exceeded initial expectations, as renewable energy on New Mexico state lands has increased more than six-fold since its inception- growing from 400 MW when Commissioner Garcia Richard assumed office to about 2.5 GW of wind and solar energy under lease today.

Here comes the Sun(Zia)

According to the American Clean Power Associations’s Clean Power Quarterly for Q1 2024, New Mexico had installed the second-most wind power capacity in the country year to date, trailing only Wyoming.

Texas and California were the top two states for under-construction projects, with 18.9 GW and 8.6 GW, respectively. New Mexico (5.2 GW), Wyoming (5.1 GW), and Arizona (4.7 GW) round out the top five states for under-construction clean power capacity, per ACP’s report.

We can expect to see New Mexico remain near the top as Pattern constructs its game-changing SunZia Wind and Transmission project; both new wind lease areas intersect its transmission line.

Wind lease areas EW-0111 (left) and EW-0113 (right) are shown shaded in red. The Southline Transmission Line is indicated in black, the SunZia Transmission Line in blue. Courtesy: New Mexico State Land Office

SunZia Transmission is a 550-mile ± 525 kV high-voltage direct current transmission line between central New Mexico and south-central Arizona with the capacity to transport clean power all the way out to California. It will utilize Pattern’s 3.5 GW SunZia Wind project, the largest wind project in the Western Hemisphere, which will be simultaneously constructed alongside SunZia Transmission. Pattern Energy recently announced that the projects are expected to generate $20.5 billion in total economic benefit, including more than $8 billion in direct capital investment, at no added cost to ratepayers, according to the results of an independent study conducted by the research firm Energy, Economic & Environment Consultants LLC. 

Pattern Energy broke ground on the project last September, and it’s expected to come online in 2026. In June, a U.S. district judge dismissed claims by Native American tribes and environmentalists who sought to halt construction along part of the $10 billion energy line, asserting the plaintiffs were years too late in bringing their challenge.

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.”

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.

CPV Rogue’s Wind would join the CPV Maple Hill Solar and the CPV Fairview Energy Center projects in Cambria County. The project would consist of 19 Vestas V-162 wind turbines.

CPV Rogue’s Wind is expected to come online in 2026. The project is part of the company’s 10 GW pipeline of renewable and dispatchable generation projects, including utility-scale power generation with carbon capture.

CPV Rogue’s Wind is the first project tied to the company’s recent partnership announcement with investment management firm Harrison Street. The partnership, in which Harrison Street acquired one-third of CPV Renewables, will support an accelerated build out of the 4 GW renewable development pipeline.

It represents the end of an era for the massive coal-fired plant, located near Farmington, New Mexico. The plant, which PNM had operated for decades, provided power for much of the state.

The shutdown of San Juan Unit 4 in September 2022 followed the retirement of Unit 1 in June of that year. The coal-fired plant had four units but was reduced to two in 2017, with the closure of Units 2 and 3. The plant first came online in 1973.

The plant’s retirement sent financial ripples through the surrounding communities. Hundreds of employees were impacted. PNM provided $11 million in severance packages to help about 200 displaced workers. About 240 mine workers received severance payments worth $9 million. Another $3 million went to job training.

PNM is the majority owner of San Juan Generation Station, but the city of Farmington has a 5% stake. The city had aimed to keep the plant open, partnering with Enchant Energy for a carbon capture and sequestration (CCS) project.

The San Juan Solar Project, which would have a capacity of 400 MW, is already on the power plant land and could start operating later this year. PNM approved a 20-year power purchase agreement (PPA) for the solar project.

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.