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

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

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

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

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

In 2023, the Joint Legislative Audit and Review Commission (JLARC) directed staff to review the impacts of the data center industry in Virginia. Now, JLARC has released its findings in the report, Data Centers in Virginia.

In the U.S., data center demand is expected to reach 35 GW by 2030, up from 17 GW in 2022, McKinsey & Company projects. Grid operators and utilities expect to see significant load growth driven by electrification, new manufacturing, and data center development. According to EPRI, 15 states accounted for 80% of data center capacity in 2023, led by Virginia, Texas, California, Illinois, Oregon, and Arizona. That concentration creates economic opportunities for states hosting data centers, but could also stress the grid.

Northern Virginia is the largest data center market in the world, constituting 13% of all reported data center operational capacity globally and 25% of capacity in the Americas. According to recent analysis from Upwind, Northern Virginia has a future power requirement of 11,077 MW. Multiple factors have contributed to Northern Virginia’s market prominence, including a strong fiber network, supply of reliable cheap energy, available land, proximity to major national customers, and the creation of a state data center tax incentive.

Dealing with ‘unconstrained’ demand

In addition to the benefits associated with new data center development, like tax revenues and construction investments, they are unsurprisingly also expected to drive an “immense” increase in energy demand, the report said. Energy demand in Virginia was “essentially flat” from 2006 to 2020 – and although the population increased during this time, this was offset by energy efficiency improvements, the report said. A report commissioned by JLARC found that “unconstrained demand for power” in the state would double within the next 10 years, mostly from the data center industry.

JLARC argues that building the infrastructure to meet unconstrained data center demand would be “very difficult,” and even trying to meet half of that demand would likely be a struggle. New solar facilities, wind generation, natural gas plants, and increased transmission capacity would all be required to meet unconstrained demand, and the number of projects needed would be “very difficult” to achieve, the report said. New solar facilities would need to be built at twice this year’s annual rate, and the amount of new wind generation required would “exceed the potential capabilities of all offshore wind sites that have so far been secured for future development.”

Even if the state only tries to meet half of unconstrained energy demand, and Virginia Clean Economy Act (VCEA) requirements are not considered, a bottleneck would likely arise in gas generation. New natural gas plants would need to be added at the rate of about one large 1,500 MW plant every two years, for 15 straight years – a cadence not seen since between 2012 and 2018. With VCEA requirements in mind, JLARC says the biggest challenges would be building enough wind, battery storage, and natural gas peaker plants, with no changes to wind generation needs.

Utility requirements and processes could help limit risks

The report notes that the projected energy demand increases from data centers have raised concerns about whether enough infrastructure can be built to keep up. PJM currently requires utilities to secure “sufficient generation capacity” plus a reserve margin, and the state requires utilities to develop plans describing how generation capacity needs will be met. However, JLARC argues that individual electric utility planning does not guarantee that the generation resources needed for the whole PJM region will be built since regional generation is not centrally planned.

If utilities can’t build enough infrastructure to keep up with demand, they could choose to delay the addition of new large load customers until there is enough generation and transmission capacity on the grid, the report said.

The costs of high demand

JLARC commissioned an independent study of electric utility cost recoveries under current rate structures and found that data centers are already paying the full cost of service, but growing energy demand is likely to increase costs for other customers as well. The large amount of new generation and transmission that needs to be built will create fixed costs that utilities will need to recover, and the difficulty associated with supplying enough energy to keep pace with growing data center demand means energy prices will likely increase for all customers, the report said. Additionally, if utilities rely on importing power, they will be at the whims of the market and its spikes in prices.

Data centers also pose a financial risk to electric utilities and their customers, the report found. For example, utilities could end up building more generation and transmission infrastructure than is needed if forecast demand does not materialize, or if several large data centers close – essentially “stranding” utilities with infrastructure costs they would have to recoup from existing customers. One risk is unique to electric co-ops: if a data center customer delays, disputes, or fails to pay an energy generation bill and the co-op cannot recoup these costs from the customer, all of the other co-op members would have to foot the bill. Finally, if data centers participate in the state’s retail choice program and purchase generation through third parties instead of their incumbent electric utility, generation costs could begin to shift to other customers, the report said.

The report also included several recommendations and policy options meant to help address data center demand in Virginia, including:

• Clarify that electric utilities have the authority to delay, but not deny, service to customers when the addition of customer load cannot be supported;
• Direct Dominion Energy to develop a plan for addressing the risk of infrastructure costs being stranded with existing customers, and file that plan with the State Corporation Commission;

Read the full report here.

The company said it now intends to run the Baldwin plant through 2027 instead of retiring in 2025, as previously announced, while still meeting federal Environmental Protection Agency retirement and pond closure obligations.   

“Vistra is committed to the responsible transition of our fleet in Illinois, and in this case, the most reasonable path forward is to continue to operate the plant as a reliable bridge to 2027, as we, and others, bring new generation assets online in the state,” said Jim Burke, president and CEO of Vistra. “As many organizations have recently raised concerns over reliability and resource adequacy in central and southern Illinois, we are taking action and delivering solutions that balance the needs of reliability, affordability, and sustainability.”

With the addition of a new 68 MW utility-scale solar and 2 MW/8 MWh energy storage system, which began generating power this month, Baldwin is now more of a power generation hub than a traditional power plant. The $135-million investment involved the placement of over 200,000 solar panels across 420 acres of property the plant has owned and maintained for decades. The solar generation facility will produce approximately 140,000 MWh annually over the next 20 years. 

The 1,185-MW Baldwin Power Plant produces enough electricity to power approximately 592,500 homes. Approximately 120 employees operate the Baldwin plant. Union employees are represented by IBEW Local 51.

Reusing plant sites

Across the country, Vistra is undertaking a “methodical, site-by-site analysis” of its coal fleet to determine the economic feasibility of repurposing the sites by retiring some technologies and renewing the plants with less carbon-intense generation, including solar and energy storage. 

The investment at the Baldwin plant site is part of the State of Illinois’ Coal-to-Solar and Energy Storage Initiative, which encouraged the development of renewable energy assets at existing power plant sites. Along with Baldwin, Vistra continues to make progress on other Coal-to-Solar sites, including:  

• The 44-MW solar and 2 MW/8 MWh energy storage facility at the Coffeen Power Plant site is generating power.
   
• Construction of the 52 MW solar and 2 MW/8 MWh energy storage facility at the Newton Power Plant will begin in 2025. 

Separately, construction has begun on a 405 MW utility-scale solar facility that will interconnect at the company’s retired EEI-Joppa Power Plant through a to-be-constructed approximate 8-mile transmission line. 

Since its merger with Dynegy in 2018, Vistra has taken steps to operate, retire, and transform its coal plant fleet in Illinois. The company has committed to retiring these plants by the end of 2027 to comply with existing federal EPA regulations.   

Economic impacts

Vistra argues that the Baldwin Power Plant provides “significant direct and indirect” economic benefits to the region and state. An economic impact study projected the plant’s direct, indirect, and induced economic benefits and concluded that within Randolph County, the existing Baldwin plant: 

• Sustains approximately 298 full-time direct, indirect, and induced jobs in the area;
• Generates more than $41 million in income for local workers in the county; and
• Has a total regional economic output of $262 million 

The new solar facility is expected to generate $6 million in total property tax payments over the project’s life, Vistra said.

Vistra and data centers

Last month, Vistra said it was engaged in discussions with large load customers for the potential sale of power from its nuclear and gas plants through long-term agreements. Stacey Doré, Vistra’s Chief Strategy and Sustainability Officer, told investors the company was pursuing deals based around multiple plants in its portfolio. She said one approach being discussed would be pursuing co-location deals at multiple sites in combination with building new generation. Doré said Vistra specifically in discussions with two large companies about building new gas plants to support a data center project. Gas plants in both PJM and ERCOT are drawing interest, she said.

The company is also in early discussions with some of the hyperscalers about nuclear uprates, Doré said. The hyperscalers are considered the companies that are predominately driving large-scale buildout of AI data centers, like Amazon, Google and Microsoft

This collaboration leverages NANO Nuclear’s advanced nuclear reactor technologies in development to provide energy for Digihost’s operations, including AI-driven data centers and digital asset colocation programs. The non-binding MOU is the first step in a broader strategic relationship, the companies said, and it establishes a framework aimed at “enhancing public understanding and community support” for nuclear energy, and particularly advanced nuclear technologies such as NANO Nuclear’s ‘ZEUS’ and ‘ODIN’ portable microreactors, which are designed to reliably and safely provide consistent and carbon-neutral baseload energy.

“The opportunity to collaborate with NANO Nuclear represents a bold move toward achieving our sustainability goals,” said Michel Amar, CEO of Digihost Technology. “By leveraging NANO Nuclear’s advanced nuclear reactor technology, we gain the potential ability to scale quickly across our existing power assets following successful initial deployment. This collaboration positions Digihost at the forefront of delivering reliable, modular baseline power, enabling the development of Tier III HPC data centers in locations previously deemed unfeasible. This strategic move also allows us to capitalize on the rapidly expanding Tier III data center market, further solidifying our leadership in the industry.”

The deployment of NANO Nuclear’s advanced nuclear reactor technology is expected to replace Digihost’s existing infrastructure, advancing Digihost’s commitment to carbon neutrality and providing baseload power for Digihost’s expanding data center operations. The project’s timeline aligns with the NANO Nuclear’s overall expectations for licensing and deployment, with reactor integration within Digihost’s operations targeted for 2031. Before deployment, the companies will conduct a site assessment of Digihost’s location, initiate site preparations and develop a phased implementation strategy, collaborate on the design, construction, testing, and commissioning of an advanced microreactor power system, and work together on regulatory and licensing activities. The companies will also look to further memorialize their relationship with definitive agreements.

The ZEUS microreactor prototype is designed to harness thermal energy for direct heat applications or to convert it into electric power. This allows for diverse applications, ranging from heating to electricity generation.

The ODIN reactor will operate at higher than conventional water-cooled reactor temperatures, which will boost resilience and conversion efficiency in generating electricity.

According to NANO, the ODIN design aims to take advantage of the natural convection of coolant for heat transfer to the power conversion cycle at full power and for decay heat removal during reactor shutdown, operational transients, and off-normal conditions.

Both microreactors use High-Assay, Low-Enriched Uranium (HALEU) fuel, are modular, and are easily transportable, NANO said.

Under the non-binding Master Power Agreement signed by the companies, Oklo would develop, construct and operate powerhouses to provide power to Switch across the United States through a series of power purchase agreements.

Switch is a builder and operator of AI, cloud and enterprise data centers. Digital infrastructure has become a significant driver of new power demand.

Since January 2016, all Switch data centers have been powered by 100% renewable energy, representing nearly 984 million kilowatt-hours of green power annually.

This latest multi-decade relationship aims help accelerate Oklo’s early powerhouse deployments and help the company scale up in response to growing demand. As of July this year, Oklo had non-binding letters of intent for about 1,350 MW of microreactor capacity, a 93% increase from its 700 MW project pipeline in July 2023, the company told investors in its Q2 earnings call. Of the 650 MW announced during the second quarter of this year, 600 MW were for data center projects. By November, Oklo’s pipeline had grown to 2,100 MW, almost entirely for data centers.

Oklo is developing next-generation nuclear power plants called “powerhouses” that run on nuclear waste. The company’s Aurora powerhouse design is a fast neutron reactor that would transport heat from the reactor core to a power conversion system and is designed to run on material from used nuclear fuel known as HALEU, or “high assay, low-enriched uranium.” The reactor builds on the Experimental Breeder Reactor-II and space reactor legacy. The Aurora powerhouse is designed to scale to 15 MW and 50 MW offerings today. Oklo is also evaluating a 100 MW or larger offering that it is developing.

Oklo argues its business model simplifies clean energy access by selling power, not power plants – offering customers a direct pathway to advanced nuclear energy. Aurora powerhouses are planned to support growing energy demands as they are deployed in the future.

Oklo’s first Aurora powerhouse is targeted for deployment in 2027 at the Idaho National Laboratory (INL). The company received a site use permit from the U.S. Department of Energy, was awarded fuel material from INL, submitted the first advanced fission custom combined license application to the U.S. Nuclear Regulatory Commission, and is developing advanced fuel recycling technologies in collaboration with the U.S. Department of Energy and U.S. National Laboratories.

The partners said this Master Agreement establishes a framework for collaboration and that individual binding agreements would be finalized as project milestones are reached.

According to NERC’s 2024 Long-Term Reliability Assessment (LTRA), “well over half” of the continent is at elevated or high risk of energy shortfalls over the next five to 10 years. The assessment highlights critical reliability challenges the power industry will face over the next decade, including satisfying rising energy growth, managing generator requirements, and removing barriers to resource and transmission development.

Generator retirements are slated to continue over the next 10 years, while electricity demand and energy growth are rapidly climbing, NERC pointed out in its LTRA. New data centers are driving a good portion of the demand growth, but electrification in various sectors and other large commercial and industrial loads (like new manufacturing facilities and hydrogen fuel plants) are also playing a part.

“Demand growth is now higher than at any point in the last two decades, and meeting future energy needs in all seasons presents unique challenges in forecasting and planning,” said Mark Olson, NERC’s manager of reliability assessments. “Meanwhile, announced generator retirements over the 10-year period total 115 gigawatts (GW) and are largely being replaced by variable generation. The resulting mix of resources will be able to serve energy needs at most times, but will need to have adequate amounts of dispatchable generators with assured fuel supplies, such as natural gas, to be reliable all the time.”

NERC’s LTRA suggests that the summer peak demand forecast is expected to rise by more than 122 GW for the 10-year period, which is 15.7% higher than the current level. Since last year’s LTRA, the 10-year summer peak demand forecast has grown by more than 50%; the winter peak demand forecast is expected to rise by nearly 14% over the 10-year period.

NERC added that compared to last year’s LTRA, there are indicators this year pointing to greater investment and enhancements in the regional planning process to support grid expansion with more transmission projects reported as either under construction or in planning for construction over the next 10 years.

“While we are encouraged by the significant increase in transmission development, industry and policymakers must address the persistent challenges of siting, permitting, and construction to ensure this growth becomes a reality,” said John Moura, NERC’s director of reliability assessments and planning analysis. “Overcoming these barriers is critical to realizing a more reliable and resilient grid.”

In its Interregional Transfer Capability Study (ITCS), NERC found that an additional 35 GW of transfer capability across the U.S. would strengthen energy adequacy under extreme conditions. Increasing transfer capability between neighboring transmission systems could potentially help alleviate energy shortfalls, and could become one of the solutions that entities put in place to address the resource adequacy issues identified in the LTRA, NERC reckons. While NERC said that multiple areas have been identified as being at “elevated risk” in extreme conditions, the Midcontinent Independent System Operator (MISO) was highlighted as not having the reserves to meet resource adequacy criteria in normal conditions as resource additions are not keeping up with generator requirements and demand growth.

NERC’s assessment offers recommendations for energy policymakers, regulators, and industry to promote actions meant to help meet growing demand and energy needs while the resource mix transitions:

• The pace of generator requirements should be “carefully scrutinized and managed” by industry, regulatory, and policy-setting organizations considering the projected reliability risks;
• Enhance the long-term assessment process by incorporating wide-area energy analysis with modeled interregional transfer capability, as found in the ITCS;
• Support from regulators and policymakers at the federal, state, and provincial levels is “urgently needed” to address siting and permitting challenges to remove barriers to resource and transmission development;
• Collaboration across regulators, electric industry, and gas industry member organizations could help address the operating and planning needs of the interconnected natural gas-electric energy system;
• Ensure essential reliability services are maintained by regional transmission organizations, independent system operators, and regulators

Originally published in Renewable Energy World.

“This is an historic moment for Virginia and the world at large,” said Virginia Gov. Glenn Youngkin. 

As part of this effort, the MIT spinout has reached an agreement with Dominion Energy Virginia to provide non-financial collaboration, including development and technical expertise, as well as leasing rights for the proposed site. Dominion currently owns the proposed site.

The proposed plant would generate about 400 MW of electricity. CFS conducted a global search for the site of this first commercial fusion plant, known as ARC, which the company will independently finance, build, own and operate.

“Our customers’ growing needs for reliable, carbon-free power benefits from as diverse a menu of power generation options as possible, and in that spirit, we are delighted to assist CFS in their efforts.” said Dominion Energy Virginia President Edward H. Baine. 

CFS is currently completing development of its fusion demonstration machine, SPARC, at its headquarters in Devens, Massachusetts. The company said it expects SPARC to produce its first plasma in 2026 and net fusion energy shortly afterward. This would be a significant achievement, as it would be the first time a “commercially relevant” design would produce more power than consumed. In CFS’ eyes, SPARC paves the way for ARC, which the company expects to deliver power to the grid in the early 2030s.

Nuclear fusion occurs when two atoms combine to form a single atom. The combined atom has less mass than the original two atoms, with large amounts of energy released in the process. Fusion is considered the holy grail of clean energy because of its potential to produce nearly limitless, carbon-free energy. But getting energy from fusion – the process that powers the sun and stars – has been a great challenge on Earth. Scientists have been trying to replicate it as far back as the 1930s.

But there have been recent breakthroughs. Researchers at the Lawrence Livermore National Laboratory (LLNL) in California for the first time produced more energy in a nuclear fusion reaction than was used to ignite it, a long-sought accomplishment known as net energy gain.

The extremely brief fusion reaction, which used 192 lasers and temperatures measured at multiple times hotter than the center of the sun, was achieved December 5, 2022.

In August 2023, the laboratory said it had achieved net energy gain once again.

Achieving net energy gain has been challenging because fusion happens at such high temperatures and pressures that it is incredibly difficult to control.

CFS was spun out of MIT in 2018. Since then, it has raised more than $2 billion in capital. In addition to this private capital, CFS has been awarded $16.5 million in grants from the U.S. Department of Energy. The most recent grant of $15 million was announced in June 2024 as part of the first phase of the DOE’s Milestone-Based Fusion Development Program.

During the outage, the Watts Bar team completed more than 12,000 work activities to return the unit to full generating capacity and supply enough energy for at least 650,000 homes.

“The work our team members completed during this outage will allow us to continue to provide safe, reliable, carbon-free electricity for people throughout the Tennessee Valley for the next 18-month operating cycle,” said Chris Reneau, Watts Bar site vice president. “As the region continues to grow at a rapid rate and the need for power grows with it, we’re appreciative that our highly skilled team of TVA, union, and contract partners works safely and with full attention to craftsmanship and operational excellence to make the upgrades and enhancements further to improve the reliability of Unit 1 and our plant.”

Inspections, upgrades, and updates

In addition to replacing 92 of Unit 1’s 193 fuel assemblies, the Watts Bar team performed inspections of reactor components and other plant systems in an effort to ensure continued safe operation of components, replaced or serviced plant equipment and installed enhancements. The team attributes the increase in power for Unit 1 to upgrades made during the outage, such as replacing two low-pressure turbine rotors and increasing the cooling tower, condenser, and plant efficiency.

Watts Bar is TVA’s second largest nuclear plant—its two pressurized water reactors produce about five percent of TVA’s total generation capacity. Each unit produces about 1,150 MW of electricity. Watts Bar Unit 1 is one of seven operational TVA nuclear reactors across the Valley, with TVA’s nuclear fleet providing more than 40% of all its electricity generated.

Over the summer, TVA named new leadership for the Watts Bar nuclear plant. Chris Reneau was named site vice president, effective June 12. Current Watts Bar Site Vice President Tony Williams stepped into the role of Vice President, Outage Services and Supplemental Resources for TVA’s entire nuclear fleet. Reneau most recently served as vice president for operations support at the TVA Nuclear Fleet Center in Chattanooga. Since joining TVA in 2009, he has held multiple leadership roles, including Senior Manager Systems Engineering, Senior Manager Design Engineering, Site Engineering Director and Director of Operations before becoming Plant Manager at the Sequoyah Nuclear Plant in 2021.

Unit 1 at Watts Bar entered commercial operations in 1996. In 1988, TVA suspended construction activities on Unit 2 due to a reduction in the predicted power demand growth. In 2007, TVA approved the completion of Unit 2 after finishing studies of energy needs, schedule, costs, environmental impacts and financial risks.

In November 2022, TVA’s Watts Bar Unit 2 completed a steam generator replacement project at the 1,150 MW facility in eastern Tennessee. Unit 2 entered service in 2016 at a construction cost of $4.7 billion.

The original steam generators were built in the 1970s using a metal alloy that prematurely developed leaks and other problems at other nuclear plants. The equipment was installed at Watts Bar in the 1980s before TVA halted work at the site due to cost overruns, employee safety concerns and a drop in projected power demand. 

TVA determined it would be too costly to replace the original steam generators when construction resumed, so Unit 2 entered service with its original steam generators. The cost to replace the steam generators rose to around $590 million and took weeks longer to install than originally expected due to weather issues.

The 1% increase in natural gas consumption in 2023 was driven by a 6.7% (2.2 Bcf/d) increase in consumption in the electric power sector, the largest natural gas consuming sector, EIA said. U.S. consumption of natural gas for power generation averaged 35.4 Bcf/d, or 40% of U.S. natural gas consumed in 2023.

On the other hand, natural gas consumption in the residential sector reached a five-year low at an average 12.4 Bcf/d in 2023, down by 8.9% (1.2 Bcf/d) from 2022, the largest year-over-year decline in the past five years. Natural gas consumption in the commercial sector decreased 4.8% (0.5 Bcf/d).

The summer of 2023 was the hottest recorded in the Northern Hemisphere, increasing consumption of natural gas in the electric power sector to meet demand for air conditioning, EIA said. Additionally, “warmer-than-normal” temperatures in January and February 2023 resulted in less demand for space heating in the residential and commercial sectors than in the past five years and reduced growth in total natural gas consumption in 2023 compared with 2022.

The natural gas consumption trends observed in 2023 largely continued in 2024 through September, EIA said. U.S. natural gas consumption through September 2024 averaged 89.8 Bcf/d, according to EIA’s monthly data, up 1% from the same period in 2023. The increase was driven by a 4% (1.6 Bcf/d) increase in consumption in the electric power sector, which averaged 38.1 Bcf/d, or 42% of U.S. natural gas consumed in 2024 through September.

Earlier this year, EIA predicted a 2% increase (35 BkWh) in natural gas generation in 2024. The increase was driven by low fuel costs and higher overall electricity demand, EIA said. A few new combined-cycle plants have come online in the past year, but the new capacity has been offset by other plants’ retirements, EIA added. Natural gas generation in 2024 is increasing the most in the Midwest (up 11 BkWh) and in the Mid-Atlantic (up 9 BkWh). The agency expects less natural gas generation in California this year (down 6 BkWh) and in the Southwest (down 2 BkWh), in response to large increases in solar generation.

On July 9, 2024, U.S. power plant operators generated 6.9 million MWh of electricity from natural gas on a daily basis in the lower 48 states, EIA said, which was “probably” the most in history, and definitely the most since at least January 1, 2019, when the EIA began to collect hourly data about natural gas generation.

The spike in natural gas-fired generation on July 9 was because of both high temperatures across most of the country and a steep drop in wind generation. According to the National Weather Service, most of the U.S. experienced temperatures well above average on July 9, 2024, with particularly high temperatures on the West Coast and East Coast.

GE Vernova did not disclose any of the customers it had signed reservations for, but Strazik noted they include data center developers. Big tech names are moving to secure generation for their power-hungry campuses, with some facilities eying launch dates as early as 2028, Bloomberg reports.

GE Vernova has generated $4 billion in cash since its split from its parent company GE nine months ago. All of the new orders will be built out of the company’s South Carolina factory. The company expects to see 20 GW of gas turbine orders each year until 2028, with at least half of those orders coming from the U.S..

“We are very well positioned to serve this market,” Strazik told CNBC’s Jim Cramer this week. “We see it every day in both our grid and our gas businesses – a substantial increase in demand.” Strazik also told Cramer the company is poised to upgrade existing nuclear plants “this decade,” while SMRs aren’t expected to become a reality until roughly 2032.

While business is booming on the gas side, GE Vernova also laid out some troubling indicators for the already-struggling U.S. offshore wind industry. “The reality is, the economics of this industry don’t make sense,” Strazik told Bloomberg. The company said it is no longer seeking new sales for its offshore turbines in the U.S., and hasn’t sold one in nearly three years.

Certainly not helping the situation was the incident at Vineyard Wind offshore wind farm, in which a GE Vernova blade broke off of the installation, causing fiberglass and other debris to wash ashore for weeks on Massachusetts beaches. GE Vernova’s offshore wind turbine manufacturing plant in Quebec, Canada fired or suspended several workers in November following a probe into the incident.

In September, GE Vernova said it planned to cut up to 900 offshore wind jobs globally in a move to reduce its offshore wind footprint. The move came not only amid uncertainty and supply chain constraints in the offshore market but also another incident involving a GE Vernova Haliade-X turbine blade – this time at the Dogger Bank Wind Farm off the northeast coast of England. However, in this case, GE Vernova said its analysis showed that the blade event was not caused by an installation or manufacturing issue but instead occurred during the commissioning process, when the turbine was left in a fixed and static position, rendering it vulnerable during a subsequent storm with high winds.