It’s the latest scrutiny CenterPoint has faced following the storm. During a Texas Senate special committee meeting this week, there were many questions about the utility’s $800 million purchase of massive, more expensive generators rather than mobile generators as intended by state law.

That legislation – SB 1075 and HB 1500 from the 88^th Texas Legislative Session – allowed utilities like CenterPoint to lease small mobile generators to quickly get power to hospitals, vulnerable populations and cooling or warming centers.

Patrick said the massive, more expensive generators purchased by CenterPoint could not be used in nearly all emergencies but allowed them to make a huge profit. He said CenterPoint testified they would make at least $30 million in profits off the backs of ratepayers.

“CenterPoint violated the spirit and purpose of the legislation by leasing generators that are not truly mobile and, as they testified, have never been deployed for an emergency,” said Patrick.

He added: “Since CenterPoint pursued profit over effectiveness, they actually had to borrow small mobile generators from those companies for Hurricane Beryl.”

The Public Utility Commission of Texas (PUC) previously approved reimbursing the $800 million to CenterPoint over time through ratepayer increases. Patrick said he would write a letter to the PUC urging them to revoke their decision to grant CenterPoint’s request for reimbursement through ratepayers.

“Call it potential fraud, deceptive practices, poor money management, or whatever you wish; CenterPoint purposely violated the intent of the legislation to make a profit while not helping their customers during a crisis,” Patrick said.

Annual U.S. sales of electricity to commercial customers in 2023 totaled 14 billion kilowatt-hours (BkWh) more than in 2019, a 1% difference. According to a new study released by EPRI, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. This could create regional supply challenges, among other issues.

Electricity demand has grown the most in Virginia, which added 14 BkWh, and. Texas, which added 13 BkWh. Commercial electricity demand in the 10 states with the most electricity demand growth increased by a combined 42 BkWh between 2019 and 2023, representing growth of 10% in those states over that four-year period.

On the other hand, demand in the forty other states decreased by 28 BkWh over the same period, a 3% decline, and commercial electricity consumption declined between 2022 and 2023 in a few states because of mild summer weather.

Virginia, the state with the highest growth in electricity demand, has become a major hub for data centers, with 94 new facilities connected since 2019 given the access to a densely packed fiber backbone and to four subsea fiber cables.

In Texas, relatively low costs for electricity and land have attracted a high concentration of data centers and cryptocurrency mining operations, the EIA said. North Dakota had the fastest relative growth at 37% (up 2.6 BkWh) between 2019 and 2023, which EIA attributed to the establishment of large computing facilities in the state.

Last month, Duke Energy announced agreements with tech giants Amazon, Google, Microsoft and Nucor to significantly accelerate clean energy deployments in the Carolinas.

In memorandums of understanding (MOUs) signed in May, the companies proposed developing new rate structures, or “tariffs,” designed specifically to lower the long-term costs of investing in clean energy technologies like new nuclear and long-duration energy storage through early commitments. 

The proposed Accelerating Clean Energy (ACE) tariffs would enable large customers like Amazon, Google, Microsoft and Nucor to directly support carbon-free energy generation investments through financing structures and contributions that address project risk to lower costs of emerging technologies. ACE tariffs would facilitate onsite generation at customer facilities, participation in load flexibility programs and investments in clean energy assets.

The EIA expects U.S. sales of electricity to the commercial sector will grow by 3% in 2024 and by 1% in 2025.

The growth of data centers has brought a slew of questions related to their development and potential co-location with generators. In a filing to the Federal Energy Regulatory Commission (FERC) this week, Exelon and American Electric Power (AEP) protested a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania.

The parties said the proposed Interconnection Service Agreement (ISA) raises unresolved questions and could result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

Most notably, Exelon and AEP asserted the pending ISA between PJM Interconnection, Susquehanna Nuclear and PPL Utilities would allow the data center to derive benefits from the transmission system without paying for them. Under the ISA as proposed, the parties said the co-located data center would not be classified as “network load” and therefore would not be required to pay PJM transmission fees.

The Rapid Integration and Commercialization Unit (RICU) at Marine Corps Air Station Miramar is a living laboratory for testing how leading LDES technologies can be integrated into utility-scale microgrid applications. The RICU is a venture between Indian Energy, the California Energy Commission (CEC), and the DOD to validate LDES technologies.

Phase 2 of research at the RICU was funded by the CEC in May 2024 through a $4.85 million agreement between the CEC and Indian Energy to demonstrate the capabilities of LDES technologies. The partnership with Indian Energy lays the foundation for deployment on CEC grants and DOD installations.

Indian Energy is a Native American-owned microgrid developer and integrator with a history of helping Tribes and the military establish energy independence. High energy costs and unreliable power are common challenges faced by sovereign territories. Microgrids can help provide resilience and predictable energy pricing in these areas. Maada’oozh, LLC, a Native American-owned energy and environmental services company, is providing the procurement, logistics, and maintenance services for Indian Energy and has been working closely with ESS to integrate the ESS Battery Energy Storage System (BESS) into the RICU.

Over the next six months, project partners will demonstrate optimal use cases in the California energy market including solar peak shifting and grid ancillary services, after which time it will be placed into commercial operation. The RICU testing facility in Miramar, California includes a microgrid connected to a solar array and features multiple connection points for energy storage.

“Iron flow technology will provide safe, sustainable long-duration energy storage to Native communities across California and the United States,” said Nicole Reiter, Vice President of Development at Indian Energy. “We are pleased to partner with ESS to deploy this critical technology and ultimately deliver energy sovereignty to Native American communities throughout North America.”

“We are pleased that the California Energy Commission has chosen this project to demonstrate the critical role that long-duration energy storage and iron flow technology will play in delivering energy security to remote communities,” said Eric Dresselhuys, CEO of ESS. “We look forward to working with Indian Energy and Marine Corps Air Station Miramar to deploy this project and continue to build the clean, secure energy future.”

According to a recent California Energy Commission report, LDES resources could grow up to 37 GW by 2045, supporting the integration of intermittent renewable energy and enabling a decarbonized, affordable and reliable grid. ESS iron flow technology is already deployed in California, with projects installed at the Sacramento Municipal Utility District (SMUD) and Burbank Water and Power (BWP), and additional deployments announced and underway both in California and worldwide.

“The CEC is proud to continue its close partnership with Indian Energy and the Marine Corps Air Station Miramar to advance long duration energy storage that can accelerate California’s clean energy progress,” said Jonah Steinbuck, Director of the R&D Division at CEC. “The Rapid Integration and Commercialization Unit is a uniquely capable facility for validating innovative long duration energy storage technologies and helping build the market confidence needed to scale these resources.”

The North American Electric Reliability Corporation (NERC) issued an alert on June 4 to generation owners and transmission planners concerning resources — like solar, wind, and batteries — that use inverters to connect to the grid. These assets are increasingly the subject of reliability concerns because of their inability to withstand grid disturbances.

NERC found that 10 large-scale grid disturbances on the bulk power system since 2016 involved the “widespread and unexpected” reduction of nearly 15,000 MW of inverter-based resource output, including 10,000 MW in the past four years. Performing dynamic simulations of the bulk power system, in addition to improved interconnection and system studies, could solve the problem, they said.

“The significantly higher complexity and software-based nature of IBR modeling when compared to synchronous machine modeling necessitates an improvement in the fundamental principles of dynamic modeling to accurately capture the performance of IBR plants,” the NERC alert said.

Episode 67 of the Factor This! podcast features Ryan Quint, who oversees engineering and security integration for the North American Electric Reliability Corporation, which oversees the reliability of the bulk power system. Subscribe wherever you get your podcasts.

NERC aims to gather responses from generation owners and transmission planners to eight proposed recommendations.

“When we have a normal grid event like that and we lose power from dozens of solar PV facilities, hundreds, or maybe even a thousand, inverters all at the same moment in time, that’s a potential recipe for a catastrophically bad day,” Ryan Quint, formerly NERC’s director of engineering and security integration, said on the Factor This! podcast in 2023.

NERC has issued more than a dozen reports in recent years diagnosing the shortfalls of IBRs. Some incidents are what the grid watchdog identifies as “faint signals” of broader implications. Others have teetered on complete grid collapse. 

The root causes of these disturbances typically involve a resource tripping offline due to a normal grid event: a tree falls on a powerline, a squirrel climbs on a substation bus, and so on. And these grid events happen every day. Due to the volume of grid disturbances, NERC’s postmortems are taking on a sterner tone. 

In its 2023 Southeast Utah Disturbance, which detailed the loss of 921 MW of solar generation from nine large-scale solar projects due to a normally-cleared fault on a faraway transmission circuit, NERC, in no uncertain terms, called out inverter original equipment manufacturers and generator owners for failing to address persistent, and previously identified, reliability issues.

Generator owners “are often not addressing performance issues that latently exist within the existing fleet,” NERC wrote, adding that in “all of the causes of abnormal performance in this event have been previously documented by NERC in past reports; however, actions were not taken.”

The disturbances have not, to this point, caused blackouts on their own. But that’s due to IBRs playing a relatively still-small role in the power system. As renewable energy rapidly displaces fossil-fueled, synchronous sources, those “faint signals” may lead to systemic failures if the industry does not remain vigilant in addressing these underlying reliability risks.

Efforts are underway to enhance the NERC reliability standards specifically related to IBR risks. The Federal Energy Regulatory Commission issued Order 901, which directed NERC to develop new or modified reliability standards. NERC is developing a comprehensive work plan regarding standards development activities to meet this directive, and is also making changes to its registration criteria and process to bring smaller projects on the bulk power system under NERC jurisdiction per a separate FERC directive. 

Originally published in POWERGRID International.

The D.C.-based nuclear startup aimed to make a big statement at Data Center World, one of the premiere conferences in the data center industry.

“Seeing it in real life, in our home city is incredible,” said Michael Crabb, Sr. Vice President of Commercial for Last Energy.

The pitch Last Energy is making is that its 20 MW pressurized water reactor can meet the power needs of data center customers, who can’t possibly get enough power these days.

“There are a host of data center developers that are trying to build projects in our target markets and maybe they can’t get power,” said Crabb. “Those are customers that we want to demonstrate our ability to build stuff in real life and work with them to help solve their problems.”

It is the least well-kept secret in both the power and data center industries that the latter will need plenty of the former, especially with the rise of artificial intelligence. The demands of AI require robust and scalable computing infrastructure, which data centers provide.

As Power Engineering has reported extensively, data centers will consume a growing share of electricity in the U.S., with no signs of slowing down. McKinsey & Company predicts these operations will double their U.S. electric demands, from 17 GW in 2022 to 35 GW by 2030.

Utilities are feeling the squeeze and are updating their load growth forecasts accordingly.

Dominion Energy has connected 94 data centers totaling over four GW of capacity over the last approximately five years, its CEO recently told investors. The utility’s territory includes Northern Virginia, which is the largest and most dynamic data center market in the world.

According to the company’s annual report filed with regulators earlier this year, data centers represented 24% and 21% of Dominion’s electricity sales in 2023 and 2022, respectively.

Demand isn’t limited to historically strong data center markets, either. Because Ohio is seeing unprecedented demand from data center customers, American Electric Power (AEP) recently filed a proposal with state regulators requiring new data centers with loads greater than 25 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Under AEP’s proposal, data centers would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Another trend is the growing size of each data center. It’s no longer uncommon to see these companies asking for 500 MW of power for a single campus. Dominion noted it is receiving requests to power larger data center campuses that require total capacity ranging from 300 MW to as many as “several gigawatts.”

All of this provides the backdrop for the conversation at conferences like Data Center World, where data center developers, operators, service providers, regulators, and increasingly, stakeholders in the power sector come together to confront these challenges collectively.

In one conversation about the evolving policy landscape surrounding data centers, panelists noted a paradigm shift where developers are leaving traditional data center markets that have become power-constrained and following the power source, rather than the other way around, like it used to be. After all, data centers could face years of delays for a firm grid connection while transmission and other infrastructure get built.

Chris Curtis, Global Head of Data Centers for Prologis, a logistics real estate company with a data center arm, said this shift of following the power has really accelerated over the 12 to 18 months.

“I think now you’re seeing a lot of potential sites that are could not only be markets, but also, frankly, off the beaten path,” he said.

Nuclear power could be a match

Last Energy was not the only advanced nuclear company in attendance at Data Center World. Data center developers increasingly view around-the-clock nuclear power as a good match for their similarly around-the-clock needs, and this was another theme at the conference.

Panel discussions included education for data center companies on key challenges like nuclear’s regulatory hurdles, long project timelines, community engagement and the need for strategic partnerships.

“Data centers sound simple, but I’m learning are absolutely not,” said Christine King, Director of Gateway for Accelerated Innovation in Nuclear (GAIN) at Idaho National Laboratory (INL). “So maybe we’re good partners as well.”

King managed expectations by saying that while more than three dozen small modular reactor (SMR) and microreactor projects have been announced, a majority are MOUs and may never reach commercial viability.

She added another challenge is scaling up these advanced nuclear projects. Investor-owned utilities, the entities capable of taking on projects of this magnitude, don’t always want to be an early mover and take on the financial risk, King said.

“We have a lot of fence sitting going on to be quite honest with you. We have a lot of customers like you who know that you need nuclear,” she told the audience. “We have utilities that have put nuclear into their integrated resource plans. They don’t want to be second, third or fourth. They want to buy the ‘nth of a kind’ unit.”

One member of the audience, a VP of Innovation at a leading data center solution company, said his company has multiple “1500 to 2000 MW campuses” in its development pipeline over the next three years.

Regarding small modular reactors, he said his company was “highly interested.” However, he expressed trepidation about nuclear’s long lead times.

“We’re very optimistic that when it gets here, it’s going to be great,” he said. “But we’re really not sure, in the meantime, where are we at really, and that gets us nervous when we’ve got these big things in front of us.”

That gets us to the more immediate: How will data centers get power as they wait for a grid hookup or before emerging technologies are ready for prime time? That was another major topic at the conference.

The solution could be onsite generation or power through a microgrid.

Todd House, a panelist representing CyrusOne, a wholesale data center operator, said the company’s preference is grid power.

“We, as a data center operator, really don’t want to be in the power plant, onsite gen or behind-the-meter generation sort of skillset, that’s not our core capability,” said House.

That said, he added a lot of data center operators are now looking at this option more seriously due to power-constrained markets.

“Oftentimes, it’s by necessity,” he said.

He said the scale of data center customers’ ambitions is “10x” what it was just a couple years ago, adding that it’s no longer uncommon to see these companies asking for 500 MW of power for a single campus.

“It seems like an arms race right now to see who could be bigger,” said Schurr, who is Chief Commercial Officer at Enchanted Rock.

The current and future demands on the grid placed by data center, crypto and manufacturing customers present an opportunity for Enchanted Rock, a company with strong bona fides in onsite and backup power generation.

With all of this demand, Schurr noted many data centers will face delays for a firm grid connection while transmission and other infrastructure get built. Interconnection could take three years on the low end or up to ten years in certain markets.

Therefore, Enchanted Rock is promoting its “Bridge-to-Grid” microgrid solution, so data centers and other power-intensive industries can build, commission and operate on their own schedules.

The company’s solution is multi-purpose, depending on the status of power. When grid power is delayed, the microgrid provides prime power to the facility. With grid power, the microgrid can provide “flexible capacity,” backing up the facility and providing power during peak conditions to prevent grid emergencies.

Typically, data centers distribute diesel generators building-by-building throughout their campus for backup power, but these generators can’t support the grid like natural gas-fired generation can.

“For us to be able to get the power we need, we have to be somewhat flexible, self-sufficient during certain hours of the year,” said Schurr. “And you can’t do that with diesel generators.”

Natural gas-fired turbines or reciprocating engines would be the workhorse of Enchanted Rock’s microgrids. Schurr said the company evaluates about ten factors at a given site to determine the appropriate technology, including the duration of bridge power, environmental constraints, and space requirements.

Schurr said if long-term backup power is needed after interconnection, using reciprocating engines for bridge power offers the advantage of already having the equipment on-site, eliminating the need for additional diesel generators. This functionality, he noted, along with reciprocating engines’ ability to start quickly, often makes them the most cost-effective solution.

In general, Schurr said he’s starting to see a trend where companies are thinking about strategically locating their facilities near gas resources. Some data centers have asked Enchanted Rock to help them with site evaluations.

“I’d say some of the some of the more forward-thinking ones are absolutely looking at gas infrastructure as a siting criteria,” said Schurr. “They’ve never had to do that before.”

Enchanted Rock said it can go to market with the microgrid as a service, where the company owns the generating assets and provides bridge power and flexible/backup power needed during the grid connection period. Schurr noted that while it’s not common due to regulatory hurdles, some data centers do want to own the generating assets.

“We find a lot of them like it as a service, they like someone to take full accountability for building it, operating it, maintaining it, so that they can focus on just adding more data center capacity,” said Schurr.

Enchanted Rock hasn’t announced many data center projects yet. However, one of its microgrid projects will be fueled by renewable natural gas (RNG) to power a Microsoft data center in San Jose, California. The project aims to ensure maximum uptime for the facility by providing backup power during grid outages. Procurement of the RNG is scheduled to begin in early 2026. 

Schurr predicts that in five years, big data centers projects won’t be able to get a firm interconnect in most locations and will have to come with flexible generation component for peaking hours. Just another hint at the paradigm shift taking place in the power sector.

“I talked to the CFO of a big utility a few months ago,” he said. “And he said, [data centers] used to come in here asking for concessions. And now it’s like, ‘do you have power’?”

This year’s show in New Orleans was no different, as the engine manufacturer was a Diamond Sponsor for the fourth year in a row.

“I do this for all the people that have joined the journey, all the growth we’re having in [power generation],” said Braden Cammauf, V.P. of FPT North America. “I want them to come in, bring their customers, bring their partners and show the same pride that I have for this division.”

Cammauf gave us a tour of the company’s booth and showcased the company’s lineup of engines designed for rental and high-volume applications, highlighting their versatility and ability to cater to various power needs efficiently.

He teased a new offering in the 500-kilowatt range for grid backup applications, indicating FPT’s continuous innovation and response to market demands. Cammauf noted that grid backup is a growth opportunity for the company.

Watch the interview above for more on FPT Industrial’s offerings.

The project will generate more than half of the facility’s energy needs. The microgrid incorporates 5 MWac solar PV and approximately 1.1 MW of battery storage and existing onsite generators. The site will generate 10 GWh of energy annually, Eaton said.

Eaton highlighted the size of the clean energy microgrid system deployed with Enel, which the companies called a “first” in Puerto Rico. In addition to powering Eaton’s manufacturing facility, the microgrid will also support the regional power grid, the companies said. Eaton also implemented efficiency measures using its intelligent power management technologies to reduce its energy footprint.

“In our administration, we continue to focus on Puerto Rico’s energy transformation that promotes increased renewable energy generation,” said Governor Pedro Pierluisi. “I congratulate Eaton for continuing to invest in Puerto Rico and supporting this transformation with the building of a clean energy microgrid that will provide them with energy resiliency, while also reducing their carbon footprint. This is the type of project that we are working to see replicated throughout the island.”

Enel North America built, owns, and operates the system on behalf of Eaton. Enel North America financed the project under an energy-as-a-service model, shifting Eaton’s investment in the microgrid system from a capital to an operational expense. Eaton provided installation knowledge and technologies for the microgrid system, including its Power Xpert microgrid solutions and power distribution equipment. 

“As the impacts of climate change worsen, large energy users are stepping up to power their facilities sustainably,” said Matt Barnes, head of distributed energy solutions at Enel North America. “Enel is proud to partner with Eaton in building a future for manufacturing that reaches beyond facility walls to support energy resiliency for the broader community. The urgency to deploy microgrids—especially in regions with vulnerable electrical infrastructure—has never been greater, and Enel is delivering the clean and flexible systems that the energy transition requires.”

Originally published in Renewable Energy World.

The combination is intended to provide power, fuel-flexibility, and energy resiliency for commercial and industrial customers. The fuel-flexibility of the Mainspring generator allows customers to dynamically switch among multiple fuel options, including low- and zero-carbon fuels, without retrofit.

The collaboration between the two companies offers power solutions, along with Schneider’s microgrid designs, construction management, and project management experience.

“Commercial and industrial facilities are dealing with increasing demands for electricity,” said Bala Vinayagam, Senior Vice President, Microgrid Line of Business for Schneider Electric. “At the same time, organizations needing power have decarbonization goals. The Mainspring Linear Generator has the potential to serve a vital role in the transition to net zero.”

He added: “Customers are provided with a pioneering microgrid solution that can generate on-site power, adapt to an evolving grid landscape, and help them meet their decarbonization goals.”

The buyer is the city of Farmington and the existing power plant was identified as the city owned-and-operated Bluffview Power Plant. According to a signed equipment supply contract, the contract is worth approximately $13.9 million. Wärtsilä equipment for the project, including the generator sets and auxiliary equipment, is expected to be delivered by January 2025.

The two Wärtsilä 34SG natural gas-fueled engines selected for this project are also capable of operating on biogas, synthetic methanol and a hydrogen blend.

MORE: Exploring the hidden value of reciprocating engines using sub-hourly grid modeling

Farmington Electric’s Bluffview Power Plant produces approximately 60 MW. It is a combined-cycle natural gas plant that was completed and commenced operation in May of 2005. The plant includes a natural gas-fired gas Combustion Turbine Generator (CTG) with a heat recovery steam generator (HRSG),
duct burner and steam turbine. The facility also includes cooling towers, circulating water pumps, sub-station, and supporting equipment to produce and deliver electricity

Wärtsilä said the new expansion will replace lost generating capacity following the closure of a coal-fired power plant. The last unit of the San Juan Generating Station, located in Farmington, was officially removed from service in September 2022.

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

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