Numerous East Coast states are counting on offshore wind projects to power tens of millions of homes and to help them transition to cleaner energy.

But putting wind turbines at sea requires the cooperation of a powerful landlord: the federal government. Soon, that government will be led by President-elect Donald Trump, who has frequently disparaged offshore wind and said he will “make sure that ends on Day 1.”

In the eight states that have passed legal mandates to reach certain amounts of offshore wind power, Trump’s second term threatens those timelines.

“This is absolutely going to create problems for how we’re going to meet our emissions goals and the energy needs for the state,” said Massachusetts state Sen. Jamie Eldridge, a Democrat who serves as vice chair on the legislative Joint Committee on Environment and Natural Resources.

For many East Coast states that lack a large land base for extensive onshore development, offshore wind in federal ocean waters is central to their plans for a power supply that doesn’t use fossil fuels. Lawmakers in Connecticut, Maine, Maryland, Massachusetts, New York, North Carolina, Rhode Island and Virginia have established mandates requiring their states to produce certain amounts of offshore wind power in the coming years. Other states have passed laws to allow for offshore wind to be added to their grids or set nonbinding planning targets to prepare for the industry’s development.

State leaders say they will continue to pursue offshore wind but realize there may be delays during the next four years.

In the meantime, some say they will continue to build out the needed electrical grid and ports to get ready for turbines, in hopes of speeding up offshore wind once Trump’s term ends. Others say they may need to consider building more onshore energy projects, including wind and solar, in the next few years to meet near-term climate goals.

“That’s something states will have to take into account,” said Dylan McDowell, executive director with the National Caucus of Environmental Legislators, a collaborative nonpartisan forum for state lawmakers. “Is [offshore wind] still feasible, or do there need to be conversations about solar, [onshore] wind, geothermal, other energy sources that could be put into the mix to help meet those goals? There’s more questions than there are answers right now.”

While a handful of offshore wind projects have already started construction or been completed, many more are in various stages of permitting or awaiting lease auctions held by the federal Bureau of Ocean Energy Management. Industry experts say the Trump administration could deny permits, cancel pending leases and halt further auctions. It could also threaten the industry’s financing by denying clean energy tax credits.

In an extreme scenario, the bureau could even side with opponents who have brought legal challenges against projects that already have been approved and retract permits issued under the Biden administration. Trump’s ability to unwind the moves made under President Joe Biden is “underappreciated,” said Timothy Fox, a vice president at ClearView Energy Partners LLC, an independent research firm.

Trump has repeated claims that offshore wind turbines are a major cause of whale mortality — an assertion that scientists say is false. Many of the groups raising concerns about whales to oppose offshore wind are funded by oil and gas donors.

Trump’s transition team did not respond to an interview request before publication.

Offshore wind also has drawn local opposition from coastal residents who fear it will worsen their views and from fishermen who worry projects could block access to key fishing areas. Meanwhile, some Republicans have pointed to the wind industry’s recent financial struggles to argue that it will increase ratepayers’ bills.

“[T]he business model for these projects has fallen well short of projections to the degree that those wind energy developers are either halting construction or asking the government for additional subsidies to make up for projected cost increases,” four Maryland Republican senators wrote to Democratic Gov. Wes Moore in April, unsuccessfully urging him to veto a financing package to boost offshore wind in that state.

Counting on offshore wind

States’ offshore wind goals were already facing difficulties. Numerous projects were canceled or delayed last year as inflation and supply chain issues raised costs dramatically. Now, political headwinds could cause greater delays.

“Offshore wind might not be a viable option over the next four years,” said Fox, the energy analyst. “Unlike a lot of other resources, offshore wind is reliant on a federal review process because these projects are being deployed in federal waters.”

Offshore wind turbines currently provide only a negligible amount of power to the United States. But a handful of projects currently under construction will soon raise that number to 4 gigawatts (1 gigawatt can power about 750,000 homes). And much more is on the way.

Developers of other projects are working to finalize financing or permits, and wind companies are awaiting federal lease auctions that will open up new areas for development. In total, the project pipeline for offshore wind exceeds 80 gigawatts, according to the National Renewable Energy Laboratory — enough to consistently power more than 60 million homes. The incoming administration could thwart most of that production by denying development permits or leases in federal waters.

East Coast states don’t have a viable way to meet their clean energy goals without that offshore production, said Maryland state Del. Lorig Charkoudian, a Democrat who authored a law last year that increased the state’s offshore wind targets.

“We’ll continue to support the ongoing development of offshore wind until we have to make other adjustments,” she said.

The Maryland law mandates that the state produce 8.5 gigawatts of offshore wind energy by 2031. Developers of a trio of projects off the state’s coast, totaling 1.7 gigawatts, are working to secure permits and financing, according to the National Renewable Energy Laboratory. And the state is counting on future lease auctions by federal regulators to prompt more development.

Charkoudian acknowledged that Trump could threaten those efforts, but she said the state remains committed to its offshore wind plans. She noted that Maryland is working to improve its electrical grid so that offshore wind projects can “land” their power, an effort that will continue.

“Even if other things do get slowed down, this will make things move faster whenever it can get moving again,” she said.

Nick Guariglia, outreach manager with the New York Offshore Wind Alliance, a network of industry and environmental groups, said that projects take many years to develop, a timeframe exceeding one presidential administration. He also noted that the maturing industry aligns with Trump’s goals of restoring manufacturing jobs and American energy independence. Members of Congress in both parties are seeing economic growth in their districts because of offshore wind, he said.

“This industry has a lot of things to prove about why it’s here to stay,” he said. “Actions are much more important than rhetoric.”

Regardless of what happens at the federal level, offshore wind backers will urge New York lawmakers to continue investing in infrastructure and workforce development to support the buildout of more turbines, he said.

Stateline is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Stateline maintains editorial independence. Contact Editor Scott S. Greenberger for questions: info@stateline.org.

2024 was another banner year for a source of electricity that is better for people’s lungs, better for climate change and may be reaching your home when you turn on the lights or turn up the thermostat — large banks of batteries.

This ability to store large amounts of electricity in batteries was essentially nonexistent a decade ago, but the country had about 24 gigawatt-hours operating as of the end of November, up a whopping 71% over the same date in 2023.

This is welcome news to clean energy advocates including Dariella Rodriguez. She has seen what happens on days when demand for air conditioning or heating spikes and extra power plants fueled by natural gas, located in Port Morris and Mott Haven, fire up not far from where she works in Hunts Point in the South Bronx, New York.

Batteries can jolt into service, sending electricity onto overhead wires, instead of these dirty “peaker” plants. Rodriguez hasn’t seen that transition yet, but she hopes to.

“The people that are exposed to these plants are the most vulnerable people in environmental justice communities already,” said Rodriguez, a director at THE POINT Community Development Corporation there, noting that lower-income people and communities of color often live near peakers.

The nation’s 1,000 peaker plants can be very dirty, inefficient and expensive, according to an analysis by the U.S. Government Accountability Office, a watchdog group that works for the U.S. Congress. Some 63 million people are estimated to live within a three-mile radius of one.

Although peakers run only a small part of the time, they release more harmful nitrogen oxides and sulfur dioxide per unit of energy, the agency said. Those two pollutants cause asthma and other breathing problems.

Peakers also release more greenhouse gases than other power plants do per unit of electricity.
Batteries are “a really obvious solution” to reducing need for peakers, says Daniel Chu, senior energy planner for the New York City Environmental Justice Alliance.

Storing extra power in batteries also extends the hours of the day that you can use clean energy.
“It’s not always sunny, the wind’s not always blowing, but energy storage can help move that generation to when it’s most needed,” said Tim Fox, managing director at research firm ClearView Energy Partners.

That’s why at least half of battery storage facilities in the U.S. are co-located with, or in some other way support solar, an AP analysis of Energy Information Administration data shows. The amount of solar energy in the U.S. is growing and surpassed the 100-gigawatt mark this year.

Another way that the addition of these batteries is helpful to the American electrical grid and grids around the world is that forecasting is getting more difficult.

“With weather patterns changing, the old ways of essentially figuring out how much capacity you need on the grid for extreme events just doesn’t work,” said Oliver Garnett, director of energy services product at the technology company Fermata Energy.

Last, global electricity demand is slated to increase — by about one-third to three-quarters by 2050, according to the Energy Information Administration. Data centers for artificial intelligence, switching vehicles to electricity and population growth are all contributing.

“‘Do we have enough power plants?’ is the classic question every utility asks every year,” said Mike Jacobs, senior energy analyst at the science nonprofit Union of Concerned Scientists. “The beauty of the batteries is that if there’s energy in them, they can be used for unexpected needs.”

Otherwise, if utilities have to find more power generation, they may keep investing in plants that burn gas or coal and account for one-quarter of the nation’s greenhouse gas emissions, instead of retiring them.

Leading the charge for adding new batteries to the grid this year was California with more than 11 gigawatt-hours operating. One way to think about this is roughly the amount of electricity that a nuclear power plant would put out over 11 hours. Then the batteries would need to be recharged to do the same thing again. It’s a limited, but meaningful amount of power. In Texas, 6 gigawatt-hours were online.

Arizona saw nearly 2 gigawatt-hours humming and Nevada — the fourth-largest deployer of storage in the U.S. — had 1.1 gigawatt-hours operational.

Some regions are lagging

Yet many states aren’t using storage yet. As of November, 86% of large-scale battery storage in the U.S. was operating in just those four states.

Some states haven’t set targets telling utilities to go out and build or buy energy storage on their own. Only 18 states have 50 megawatt-hours or more operating.

Others don’t have as much clean electricity to pair with the batteries, or claim storage isn’t reliable in times of crisis. It can also be challenging to connect storage to the grid. Still, experts expect more momentum.

Especially in California and Texas, “That investment and that experiment is paying off very well,” said John Hensley, senior vice president of markets and policy analysis at American Clean Power.

“The word is getting out,” he said. “We’re increasingly seeing the technology move to other parts of the country.”

The blade tip, which is being developed in ORNL’s carbon fiber technology center, incorporates two layers each of standard glass fiber and a low-cost lab developed carbon fiber, with such customized conductive carbon fiber key to dispersing electrical energy across the blade surface.

The researchers also declare using industry-standard equipment and methods to show that the technology can be easily integrated with established manufacturing processes.

“We don’t have enough data to know the true scope of the challenge [of lightning strike damage], but we know it’s a concern to industry and utilities,” said ORNL researcher Vipin Kumar.

“We know wind energy is a reliable source of electricity that supports energy security, but I believe anything we can do to make it more resilient and reliable is important.”

Lightning strikes to wind turbine blades are known to be frequent but are rarely catastrophic.

Nevertheless, they are believed to be able weaken blades with internal damage that can translate to increased repair costs over time, and they are the second leading cause of blade-related downtime.

In the project an entire 2m turbine blade tip was built using the novel materials. This was then tested against the forces of simulated lightning in a specialized lab at Mississippi State University, where the blade tip emerged pristine after tests that isolated the effects of high voltage.

Separate tests in the same lab found that isolated high current remained destructive.

The cost of carbon fiber has generally limited its use to the wind blade’s load bearing structure, but ORNL’s efforts to lower the cost of carbon fiber may make it economical to replace glass fibers in the blade tip, where the lightning strikes most often.

With the demonstration highlighting the possibilities of a new approach to protecting blades using conductive materials or coatings, further innovations are being investigated.

With resin making up the largest portion of the blade tip, these include the use of a more conductive resin.

Another notable benefit of the hybrid carbon fiber composite blade tip is its weight, about 41% lighter than a pure glass fiber blade tip, opening the way for larger blades of the same weight, with the potential to generate more electricity.

The approach also is considered of potential for preventing lightning damage to the composites used in airplanes.

Originally published by Power Engineering International.

The project is called Mission H2 Power, and will support the decarbonization of SSE’s Keadby 2 Power Station in North Lincolnshire, which is powered by Siemens Energy’s SGT5-9000HL gas turbine.

The multi-million-pound co-investment will see Siemens Energy develop a combustion system for its SGT5-9000HL gas turbine capable of operating on 100% hydrogen, while maintaining the flexibility to operate with natural gas and any blend of the two.

This will see additional facilities constructed at Siemens Energy’s Clean Energy Centre in Berlin to allow testing of the technology for large gas turbines to take place.

Finlay McCutcheon, managing director of SSE Thermal, commented in a statement: “We know hydrogen-fired power stations will be an essential element of the energy mix in a net zero world and Mission H2 Power will help us accelerate their deployment through engineering excellence.

“…Our projects will be pivotal in providing flexible backup to renewables and while we still need to see a rapid acceleration in policy and deployment, the need for this technology is beyond question – it is a matter of when not if and this partnership can help us reach that destination as soon as possible.”

Darren Davidson, vice president of Siemens Energy UK&I, added: “We are living in a transformative time for the energy sector. Our HL-class gas turbine has set records for efficiency and power performance. This new collaboration is a significant step in reaching the point where large gas turbines can run on 100% hydrogen.”

Investment in Mission H2 Power aligns with SSE’s commitment to transition away from the use of unabated fossil fuels in electricity generation and accelerate hydrogen projects.

SSE is also working on the Keadby Next Generation Power Station project in partnership with Equinor, to ensure the plant is capable of running on either hydrogen or natural gas, or a blend of the two. This allows for flexibility in the event of delays to the hydrogen infrastructure.

Delivering low-carbon power stations will be essential to providing a clean power system in the UK, with the plants fulfilling a vital role as flexible back-up in a renewables-led system. Analysis from National Energy System Operator shows that around 7GW of low-carbon flexible power will likely be needed on the system by 2035, with around half of that capacity provided by hydrogen-fired power stations.

Originally published in Power Engineering International.

The report, The Future of Geothermal Energy, finds that geothermal energy could meet 15% of global electricity demand growth between now and 2050 if project costs continue to decline.

Today, geothermal meets about 1% of global electricity demand. However, the IEA analysis, conducted in collaboration with Project InnerSpace, shows that next-generation geothermal technologies have the technical potential to meet global electricity and heat demand many times over.

Importantly, geothermal energy can draw upon the expertise of today’s oil and gas industries by using existing drilling techniques and equipment to go deeper under the earth’s surface to tap into vast low-emissions energy resources.

“New technologies are opening new horizons for geothermal energy across the globe, offering the possibility of meeting a significant portion of the world’s rapidly growing demand for electricity securely and cleanly,” said IEA executive director Fatih Birol. “What’s more, geothermal is a major opportunity to draw on the technology and expertise of the oil and gas industry. Our analysis shows that the growth of geothermal could generate investment worth $1 trillion by 2035.”

Conventional geothermal remains a location-specific, niche technology today with most of the installed capacity in countries that have either have volcanic activity or straddle tectonic fault lines, which make resources easier to access.

Current leaders in the space include the United States, Iceland, Indonesia, Türkiye, Kenya and Italy.

But new technologies are making the outlook for geothermal truly global, opening up the potential to benefit from it in nearly all countries.

The report highlights that more than 100 countries have policies in place for solar PV and onshore wind, but only 30 have such policies for geothermal.

Moving geothermal up national energy agendas with specific goals and backed support for innovation and technology development can go a long way to reducing project risk perception and unlocking new investment.

Clear, long-term regulatory visibility for investors will help mitigate risks in early-stage development and provide visibility on investment returns, which in turn will improve the cost competitiveness of geothermal projects.

By doing so, the report finds that costs could fall by 80% by 2035 to around $50 per megawatt hour (MWh). This would make geothermal the cheapest source of dispatchable low-emissions electricity on a par with existing hydropower and nuclear installations.

However, permitting and administrative red-tape are proving a major barrier to geothermal projects, which can take up to a decade to fully commission. The report suggests governments could simplify permitting processes by consolidating and accelerating the administrative steps involved.

They could also consider dedicated geothermal permitting regimes separate from minerals mining. Policies and regulations enforcing robust environmental standards are critical for the sustainable development of geothermal projects.

Originally published in Power Engineering International.

By Joey Mashek, U.S. Sales and Strategy Director, Energy Group, Burns & McDonnell

The evolving regulatory landscape has presented power generation utilities with a complex choice as they consider large-scale gas generation projects and whether to build simple-cycle or combined-cycle power plants. With the U.S. Environmental Protection Agency’s (EPA) updated New Source Performance Standards (NSPS) for greenhouse gas (GHG) emissions, decision-makers must carefully balance operational efficiency, financial feasibility and output needs, while maintaining regulatory compliance. While results of the recent election and new administration may lead to some uncertainty with NSPS, the rule is currently still in effect.

The EPA’s NSPS aim to reduce greenhouse gas emissions from new and modified gas turbine power plants. Originally set at 1,000 pounds of carbon dioxide (CO2) per megawatt-hour (MWh), the standard under 40 Code of Federal Regulations (CFR) 60 Subpart TTTTa is now 800 pounds per MWh, with a further reduction to 100 pounds per MWh beginning January 2032.

These new standards significantly influence the decision between simple-cycle and combined-cycle plants, as they dictate whether plants can operate as baseload units or must operate at a lower imposed capacity factor if the above limits cannot be met. Adding further complexity, the updated standard introduces the concept of intermediate load facilities, with a required limit of 1,170 pounds per MWh and a capacity factor limit of 40%.

Combined-Cycle plants: High-efficiency, higher cost

Combined-cycle gas plants have traditionally been preferred as a baseload technology due to their higher efficiency. These plants utilize both a gas turbine and a steam turbine, significantly improving fuel efficiency compared to simple-cycle setups. While they are more expensive up front, their main advantage is generating more electricity from the same amount of fuel (which also results in a lower CO2 per MWh emissions rate).

However, complying with the upcoming limit of 100 pounds per MWh will require future baseload facilities to incur significant additional costs to mitigate carbon emissions, most likely through CCUS technology. CCUS technology also requires a large amount of auxiliary power, which would offset some of the traditional efficiency advantage of combined-cycle plants. For example, a 1×1 J-class combined-cycle plant with CCUS might generate roughly 750 megawatts (MW) of capacity with duct-firing but the auxiliary power requirements associated with CCUS might reduce the effective output to about 600 MW. While employing CCUS would allow the plant to continue operating as an unrestricted baseload facility, the economic impact of deploying carbon capture must be considered.

Alternately, utilities could forego the investment in CCUS and opt to build combined-cycle plants as intermediate load facilities, which then would be limited to a 40% capacity factor under the current rules. This decision would sacrifice a significant portion of the facilities’ potential energy production each year.

Simple-Cycle plants: Flexibility at a lower cost with trade-offs

Simple-cycle gas plants offer different advantages and trade-offs. They are generally cheaper to build and operate, with a less complex design and lower initial investment. Simple cycle plants are often used for peaking power, making them an attractive option for utilities needing to respond quickly to fluctuating demand.

From an emissions perspective, modern J-Class combustion turbines can meet the 1,170 pounds per MWh limit on their own. Given their lower output and efficiency, utilities are unlikely to invest in CCUS technology behind simple-cycle engines, which would put them in the intermediate load category.

In the case of simple-cycle plants, decision-makers must evaluate the levelized cost of electricity over the life of the facility. Simple-cycle plants have lower up-front costs, but efficiency would still be less than that of combined-cycle plants (even with CCUS), leading to higher fuel expenses over time. Utilities need to weigh whether the reduced initial investment would offset potentially higher operational costs, especially with fluctuating fuel prices.

A situational decision: Balancing needs and constraints

The choice between simple-cycle and combined-cycle gas plants is situational, depending on several unique factors for each project. For utilities seeking higher efficiency and baseload power, combined-cycle plants with carbon capture may be ideal, despite higher up-front costs. Conversely, utilities prioritizing flexibility and lower initial costs may find simple-cycle plants more advantageous for covering peak demand. Capacity needs are critical to the decision, and under the current rules there are more options to consider than ever before.

As an example, if a utility needs approximately 600 megawatts (or 5,250 gigawatt-hours per year) of replacement generation, a combined-cycle setup could achieve this with fewer units and greater efficiency, while a simple-cycle approach would require multiple smaller units. The decision also depends on the utility’s anticipated emissions profile and willingness to invest in emissions-reducing technologies, like CCUS.

Additionally, utilities must consider other constraints, such as land availability, project timelines and financial resources, when making a decision. As lead times for acquiring equipment increase and regulatory pressures grow, it is essential to begin the decision-making process early and to thoroughly evaluate all variables.

Navigating complex choices

Unfortunately, there is not a clear choice between simple-cycle and combined-cycle gas plants under the updated NSPS. The decision depends on each utility’s specific needs, priorities and constraints. Combined-cycle plants offer higher efficiency and baseload capacity but come with significant costs, especially when incorporating carbon capture. Simple-cycle plants are more economical upfront but may struggle to meet future emissions standards.

Ultimately, utilities must balance efficiency, cost and compliance while staying attuned to regulatory changes. Engaging with peers, staying informed about technological advancements, and starting early are critical steps in successfully navigating these complex decisions.

Comparison chart: Simple-Cycle vs. Combined-Cycle gas plants

Originally published by Burns & McDonnell. See original article here.

Across the U.S. and worldwide, energy demand is soaring as data centers work to support the wide and growing use of artificial intelligence. These large facilities are filled with powerful computers, called servers, that run complex algorithms to help AI systems learn from vast amounts of data.

This process requires tremendous computing power, which consumes huge quantities of electricity. Often, a single data center will use amounts comparable to the power needs of a small town. This heavy demand is stressing local power grids and forcing utilities to scramble to provide enough energy to reliably power data centers and the communities around them.

My work at the intersection of computing and electric power engineering includes research on operating and controlling power systems and making the grid more resilient. Here are some ways in which the spread of AI data centers is challenging utilities and grid managers, and how the power industry is responding.

Upsetting a delicate balance

Electricity demand from data centers can vary dramatically throughout the day, depending on how much computing the facility is doing. For example, if a data center suddenly needs to perform a lot of AI computations, it can draw a huge amount of electricity from the grid in a period as short as several seconds. Such sudden spikes can cause problems for the power grid locally.

Electric grids are designed to balance electricity supply and demand. When demand suddenly increases, it can disrupt this balance, with effects on three critical aspects of the power grid:

• Voltage can be thought of as the push that makes electricity move, like the pressure in a water hose. If too many data centers start demanding electricity at the same time, it’s like turning on too many taps in a building at once and reducing its water pressure. Abrupt shifts in demand can cause voltage fluctuations, which may damage electrical equipment.
• Frequency is a measurement of how electric current oscillates back and forth per second as it travels from power sources to load demand through the network. The U.S. and most major countries transmit electricity as alternating current, or AC, which periodically reverses direction. Power grids operate at a stable frequency, usually 50 or 60 cycles per second, known as hertz; the U.S. grid operates at 60 Hz. If demand for electricity is too high, the frequency can drop, which can cause equipment to malfunction.
• Power balance is the constant real-time match between electricity supply and demand. To maintain a steady supply, power generation must match power consumption. If an AI data center suddenly demands a lot more electricity, it’s like pulling more water from a reservoir than the system can provide. This can lead to power outages or force the grid to rely on backup power sources, if available.

Peaks and valleys in power use

To see how operating decisions can play out in real time, let’s consider an AI data center in a city. It needs 20 megawatts of electricity during its peak operations – the equivalent of 10,000 homes turning on their air conditioners at the same time. That’s large but not outsize for a data center: Some of the biggest facilities can consume more than 100 megawatts.

Many industrial data centers in the U.S. draw this amount of power. Examples include Microsoft data centers in Virginia that support the company’s Azure cloud platform, which powers services such as OpenAI’s ChatGPT, and Google’s data center in The Dalles, Oregon, which supports various AI workloads, including Google Gemini.

The center’s load profile, a timeline of its electricity consumption through a 24-hour cycle, can include sudden spikes in demand. For instance, if the center schedules all of its AI training tasks for nighttime, when power is cheaper, the local grid may suddenly experience an increase in demand during these hours.

Here’s a simple hypothetical load profile for an AI data center, showing electricity consumption in megawatts:

• 6 a.m.-8 a.m.: 10 MW (low demand)
• 8 a.m.-12 p.m.: 12 MW (moderate demand)
• 12 p.m.-6 p.m.: 15 MW (higher demand due to business hours)
• 6 p.m.-12 a.m.: 20 MW (peak demand due to AI training tasks)
• 12 a.m.-6 a.m.: 12 MW (moderate demand due to maintenance tasks)

Ways to meet demand

There are several proven strategies for managing this kind of load and avoiding stress to the grid.

First, utilities can develop a pricing mechanism that gives AI data centers an incentive to schedule their most power-intensive tasks during off-peak hours, when overall electricity demand is lower. This approach, known as demand response, smooths out the load profile, avoiding sudden spikes in electricity usage.

Second, utilities can install large energy storage devices to bank electricity when demand is low, and then discharge it when demand spikes. This can help smooth the load on the grid.

Third, utilities can generate electricity from solar panels or wind turbines, combined with energy storage, so that they can provide power for periods when demand tends to rise. Some power companies are using this combination at a large scale to meet growing electricity demand.

Fourth, utilities can add new generating capacity near data centers. For example, Constellation plans to refurbish and restart the undamaged unit at the Three Mile Island nuclear plant near Middletown, Pennsylvania, to power Microsoft data centers in the mid-Atlantic region.

In Virginia, Dominion Energy is installing gas generators and plans to deploy small modular nuclear reactors, along with making investments in solar, wind and storage. And Google has signed an agreement with California-based Kairos Power to purchase electricity from small modular nuclear reactors.

Finally, grid managers can use advanced software to predict when AI data centers will need more electricity, and communicate with power grid resources to adjust accordingly. As companies work to modernize the national electric grid, adding new sensor data and computing power can maintain voltage, frequency and power balance.

Ultimately, computing experts predict that AI will become integrated into grid management, helping utilities anticipate issues such as which parts of the system need maintenance, or are at highest risk of failing during a natural disaster. AI can also learn load profile behavior over time and near AI data centers, which will be useful for proactively balancing energy and managing power resources.

The U.S. grid is far more complicated than it was a few decades ago, thanks to developments such as falling prices for solar power. Powering AI data centers is just one of many challenges that researchers are tackling to supply energy for an increasingly wired society.

Anurag Srivastava, Professor of Computer Science and Electrical Engineering, West Virginia University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

NEW ORLEANS (AP) — The largest artificial intelligence data center ever built by Facebook’s parent company Meta is coming to northeast Louisiana, the company said Wednesday, bringing hopes that the $10 billion facility will transform an economically neglected corner of the state.

Republican Gov. Jeff Landry called it “game-changing” for his state’s expanding tech sector, yet some environmental groups have raised concerns over the center’s reliance on fossil fuels — and whether the plans for new natural gas power to support it could lead to higher energy bills in the future for Louisiana residents.

Meanwhile, Elon Musk’s AI startup, xAI, is expanding its existing supercomputer project in Memphis, Tennessee, the city’s chamber of commerce said Wednesday. The chamber also said that Nvidia, Dell, and Supermicro Computer will be “establishing operations in Memphis,” without offering further details.

Louisiana is among a growing number of states offering tax credits and other incentives to lure big tech firms seeking sites for energy-intensive data centers.

The U.S. Commerce Department found that there aren’t enough data centers in the U.S. to meet the rising AI-fueled demand, which is projected to grow by 9% each year through 2030, citing industry reports.

Meta anticipates its Louisiana data center will create 500 operational jobs and 5,000 temporary construction jobs, said Kevin Janda, director of data center strategy. At 4 million square feet (370,000 square meters), it will be the company’s largest AI data center to date, he added.

“We want to make sure we are having a positive impact on the local level,” Janda said.

Congressional leaders and local representatives from across the political spectrum heralded the Meta facility as a boon for Richland parish, a rural part of Louisiana with a population of 20,000 historically reliant on agriculture. About one in four residents are considered to live in poverty and the parish has an employment rate below 50%, according to the U.S. census data.

Meta plans to invest $200 million into road and water infrastructure improvements for the parish to offset its water usage. The facility is expected to be completed in 2030.

Entergy, one of the nation’s largest utility providers, is fast-tracking plans to build three natural gas power plants in Louisiana capable of generating 2,262 megawatts for Meta’s data center over a 15-year period — nearly one-tenth of Entergy’s existing energy capacity across four states.

The Louisiana Public Service Commission is weighing Entergy’s proposal as some environmental groups have opposed locking the state into more fossil fuel-based energy infrastructure. Meta said it plans to help bring 1,500 megawatts of renewable energy onto the grid in the future.

Louisiana residents may ultimately end up with rate increases to pay off the cost of operating these natural gas power plants when Meta’s contract with Entergy expires, said Jessica Hendricks, state policy director for the Alliance for Affordable Energy, a Louisiana-based nonprofit advocating for energy consumers.

“There’s no reason why residential customers in Louisiana need to pay for a power plant for energy that they’re not going to use,” Hendricks said. “And we want to make sure that there’s safeguards in place.”

Public service commissioner Foster Campbell, representing northeast Louisiana, said he does not believe the data center will increase rates for Louisiana residents and views it as vital for his region.

“It’s going in one of the most needed places in Louisiana and maybe one of the most needed places in the United States of America,” Foster said. “I’m for it 100%.”

Environmental groups have also warned of the pollution generated by Musk’s AI data center in Memphis. The Southern Environmental Law Center, among others, says the supercomputer could strain the power grid, prompting attention from the Environmental Protection Agency. Eighteen gas turbines currently running at xAI’s south Memphis facility are significant sources of ground-level ozone, better known as smog, the group said.

Patrick Anderson, an attorney at the law center, said xAI has operated with “a stunning lack of transparency” in developing its South Memphis facility, which is located near predominantly Black neighborhoods that have long dealt with pollution and health risks from factories and other industrial sites.

“Memphians deserve to know how xAI will affect them,” he said, “and should have a seat at the table when these decisions are being made.”

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.

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.