A 40-year-old Pennsylvania facility that is among the nation’s younger nuclear power plants is the first to win approval to replace its analog safety systems with a single digital system.
The Nuclear Regulatory Commission (NRC) said Jan. 5 that its approval of the digital upgrade at Constellation Energy’s Limerick Clean Energy Center paves the way for instrumentation and control modernization across the U.S. commercial fleet.
Operators of other facilities have taken advantage of regulatory flexibilities to make limited, targeted digital upgrades, NRC said, but the Limerick project is the first authorized to take a broad, comprehensive approach. Much of the U.S. fleet still relies on analog controls.
Constellation said Jan. 6 that the $167 million overhaul will be performed in phases to maintain operational continuity, with major work planned when the reactors are taken offline for refueling.
The company said the Limerick Digital Modernization Project would enhance safety system reliability and cybersecurity; significantly reduce manual maintenance, testing and surveillance requirements; enhance operator interfaces and diagnostic capabilities; reduce plant operating and maintenance costs; and eliminate obsolete components.
The effort is part of Constellation’s $5.1 billion effort to preserve and expand the capacity of its nuclear fleet in Pennsylvania and comes as the Trump administration tries to bolster nuclear power generation nationwide. It is supported by the U.S. Department of Energy’s Light Water Reactor Sustainability Program.
The NRC license amendments place some requirements on the project but conclude that the changes will not endanger the health, safety and security of the public (Docket Nos. 50-352 and 50-353).
Limerick Clean Energy Center is 35 miles southeast of Philadelphia. Its two General Electric boiling water reactors are rated at a combined 2,317 MW. They operated at a capacity factor of 95.2% to generate a net 19.36 million MWh of electricity in 2024.
Unit 1 entered commercial service in February 1986 and Unit 2 in January 1990.
In October 2014, the NRC renewed the operating licenses for Unit 1 through October 2044 and Unit 2 through June 2049.
MISO announced it will partner with Microsoft’s AI technologies to operate its markets and plan its system.
MISO said it would create a “unified data platform designed to transform how the grid is planned, operated and optimized” with Microsoft’s help. The grid operator said it will incorporate cloud computing platform Microsoft Azure and Microsoft Foundry’s generative AI technologies.
“Partnering with Microsoft allows us to harness the full power of advanced analytics, AI and cloud platforms to improve forecasting, enhance decision-making and build resilience into our operations. Ultimately, these advancements benefit our members and stakeholders,” MISO CIO and Vice President Nirav Shah said in a Jan. 6 press release.
MISO said it should be able to better predict and detect grid conditions and make faster, data-driven decisions by integrating these versions of machine learning and insights from massive datasets on the cloud. It said the move will help it make more proactive decisions during disruptions like extreme weather events and improve real-time reliability.
The RTO said it would use Microsoft Foundry to devise better grid forecasts and long-range transmission planning. MISO’s engineers and operators would use tools like Microsoft Power BI’s interactive data visuals and AI chatbot Microsoft 365 Copilot to assist in their work, it added.
MISO began using AI to influence decisions in the control room in 2024, but said over fall 2025, its AI-based risk prediction model failed to foresee the highest risk days of the season. (See “Risk Predictor not Quite There Yet,” MISO Usage, Outages Up in Fall 2025.)
MISO said the data platform should cut some of its work from “weeks to minutes” and would allow MISO to pinpoint and avoid transmission congestion before it occurs.
“Such acceleration is critical because of the increasing diversity of energy mix, electrification, rising demand and the growth of data centers,” Shah said, adding that “now is the time to partner with organizations that share a common interest in modernizing the grid operations of the future.”
Darryl Willis, Microsoft corporate vice president of energy and resources industry, said the partnership is a “bold step forward in modernizing one of North America’s most complex and critical electricity markets.” Willis said Microsoft’s AI capabilities and cloud-based analytics can build a “future-ready, more resilient and sustainable grid that can anticipate challenges, optimize performance and deliver reliable power as electrification and demand grow.”
MISO said the new partnership is its way of “taking a leadership role in ensuring that digital transformation benefits are shared across the grid.”
The U.S. Department of Energy has awarded $900 million each to three companies to help expand the country’s uranium-enrichment capabilities.
The Jan. 5 announcement is the latest step in a long-running effort to expand domestic production of the fuel that generates approximately 19% of U.S. electricity — almost all of which is imported. If the widely held ambitions for expanded nuclear generation come to fruition, much more enriched uranium will be needed.
DOE intends its awards to expand capacity for the low-enriched uranium (LEU) used in most commercial reactors and to foster innovation and supply chain development in the high-assay low-enriched uranium (HALEU) that some next-generation nuclear reactors will use. The $2.7 billion will be disbursed as milestones are reached over the next decade.
The recipients are American Centrifuge Operating, to create domestic HALEU enrichment capacity; General Matter, to create domestic HALEU enrichment capacity; and Orano Federal Services, to expand domestic LEU enrichment capacity.
DOE also awarded $28 million to Global Laser Enrichment to continue development of its next-generation uranium enrichment technology.
The announcement came two weeks after American Centrifuge’s corporate parent, Centrus Energy, announced it had begun domestic centrifuge manufacturing to support commercial LEU enrichment activities at its Piketon, Ohio, facility. Centrus said it has secured $2.3 billion in contingent LEU sales and is working toward future HALEU production.
Orano said Jan. 5 that the DOE award would support development of its planned uranium enrichment facility in Oak Ridge, Tenn., which has an anticipated price tag of $5 billion. The company has named it “Project IKE” after President Dwight D. Eisenhower’s “Atoms for Peace” speech to the U.N. in 1953. It expects to submit the facility design to the Nuclear Regulatory Commission soon and hopes to build it quickly enough to begin LEU production in 2031.
The company has supplied enriched uranium to the U.S. reactor fleet for 40 years from production facilities in France and intends to continue this with production in Tennessee.
“Orano is the only Western company in the last 15 years that has successfully built and operated a new, modern, commercial-scale gas centrifuge uranium enrichment facility with our completion of the Georges Besse II facility in 2011. Plus, we are currently performing a 30% capacity expansion of this facility,” said François Lurin, executive vice president of Orano’s Chemistry and Enrichment business. “Our objective is to apply the best practices from that construction and expansion to the benefit of the Project IKE uranium enrichment facility in Tennessee.”
U.S. Energy Secretary Chris Wright said the awards would reduce U.S. reliance on foreign suppliers as the country works toward energy security: “Today’s awards show that this administration is committed to restoring a secure domestic nuclear fuel supply chain capable of producing the nuclear fuels needed to power the reactors of today and the advanced reactors of tomorrow.”
Three of the four developers building wind farms in U.S. waters are challenging the Trump administration’s Dec. 22 order suspending all such construction.
Some light soon may be shed on the reasoning for the stop-work order, although not publicly: The federal government said it should, during the week of Jan. 5, be able to provide classified information bearing “secret” or higher classification to a judge hearing the first of the challenges.
Coastal Virginia Offshore Wind (CVOW) developer Dominion Energy sought a preliminary injunction Dec. 23 in U.S. District Court for the Eastern District of Virginia.
Revolution Wind, a joint venture of Skyborn Renewables and Ørsted, challenged the suspension Jan. 1 in U.S. District Court for the District of Columbia.
Empire Wind developer Equinor challenged the suspension on Jan. 2, also in U.S. District Court for the District of Columbia.
Avangrid and Copenhagen Infrastructure Partners have not announced any response to the suspension of Vineyard Wind 1, which is in late stages of construction and already generating power with some of its turbines.
The only other wind farm being built in U.S. waters is Sunrise Wind, which is in earlier stages of construction. Developer Ørsted said it is considering its options for how to respond to the Sunrise suspension.
The direction of the greatly diminished U.S. offshore wind sector rides on these challenges, as no other projects appear likely to start construction during the Trump administration.
The Department of the Interior said the pause would give all relevant government agencies time to work with the leaseholders and state governments to mitigate those risks.
But the pause also will cause the developers to incur millions of dollars in unbudgeted expenses per day.
Dominion was first in line to fight back.
It said it has spent $8.9 billion of CVOW’s projected $11.2 billion cost to date and already begun recovering that money from ratepayers. It called the order by the U.S. Bureau of Ocean Energy Management arbitrary and illegal, as well as inconsistent with BOEM’s previous actions during its “extraordinarily thorough” reviews of the CVOW proposal during a yearslong permitting process.
Interior indicated its Dec. 22 pause came in response to a situation that evolved after the BOEM permitting and said some of the explanation for this was classified.
Judge Jamar Walker on Dec. 28 converted Dominion’s request for a temporary restraining order to a motion for a preliminary injunction and set a Jan. 16 hearing on the motion. He gave Interior until Jan. 9 to provide the classified information that he called critical to evaluating the case.
‘Patently Unlawful’
The complaint filed Jan. 1 by Revolution Wind is another chapter in its running battle with Interior over the stop-work order the department had slapped on it Aug. 22.
Judge Royce Lamberth ordered that stop-work order lifted Sept. 22, and Revolution is asking him to do the same with the Dec. 22 order, saying it too is “patently unlawful” and violates the Administrative Procedure Act (APA), the Outer Continental Shelf Lands Act (OCSLA) and the U.S. Constitution.
In its news release, Ørsted said Revolution is 87% complete, with 58 of 65 turbines installed. It had been set to start generating power later in January.
The Danish company said Aug. 25 that total investment in Revolution and Sunrise was expected to be approximately $15.6 billion.
Empire Wind also is a two-time target of the Trump administration, which slapped a stop-work order on it in April but lifted it a month later without court intervention.
Empire said in its Jan. 2 filing that the April stop-work order cost it $200 million in delay costs and drove the project to the brink of cancellation. It said this new stop-work order likely will result in project cancellation if it lasts 90 days — the developer cannot draw down on construction financing and the complex, highly choreographed schedule would be thrown off.
Empire said the project is approximately 60% complete at a cost of more than $4 billion so far, $1.5 billion of it since the April stop-work order was lifted.
Empire asks the court to vacate the suspension and to declare it unlawful, arbitrary and capricious, an abuse of discretion, and a violation of APA and OCSLA. It seeks a preliminary injunction as the case proceeds through the legal system.
FERC has approved a settlement between Luminant Generation and the Texas Reliability Entity for violations of a regional reliability standard governing primary frequency response in the ERCOT region (NP26-2).
NERC submitted the settlement Nov. 26 in its monthly spreadsheet Notice of Penalty (SNOP); FERC said in a Dec. 23 filing that it would not further review the agreement. The settlement carries no monetary penalty.
Luminant’s settlement concerned violations of BAL-001-TRE-2 (Primary frequency response in the ERCOT region), a regional standard approved by NERC’s Board of Trustees in 2020 and approved by FERC the same year. (See “Standards Actions,” NERC Board of Trustees Briefs: Feb. 6, 2020.) Requirement R9 of the standard specifies the 12-month minimum rolling average value of each generating unit’s initial primary frequency response (PFR) performance, while requirement R10 sets the minimum sustained PFR.
The utility self-reported both violations, the first on Aug. 18, 2022. On that date, Luminant notified Texas RE that it had not set the required initial PFR at four generating units: Unit 1 at the Lake Hubbard gas plant, Unit 1 at the Odessa-Ector combined cycle plant, Unit 2 at the Oak Grove coal plant and the Castle Gap solar plant.
Lake Hubbard was the first to fall below the required value on Aug. 31, 2021. That unit and the Odessa-Ector unit have since been reset and returned to compliance; the other two were still noncompliant at the time the SNOP was filed, although mitigation efforts — including reviews of the plant controller logic and updates to turbine control and distributed control systems for Oak Grove and correcting high sustainable limit telemetry for Castle Gap — were ongoing. The SNOP did not provide an estimated date of completion for the mitigation.
Luminant reported its noncompliance with requirement R10 to Texas RE on June 30, 2023, notifying the regional entity that the average sustained PFR at Lake Hubbard 1, Oak Grove 1 and 2, and Castle Gap had fallen below the required value. Only Lake Hubbard had returned to compliance at the time of the SNOP. Similar mitigation measures to those for the R9 infringements were underway at the affected plants.
Texas RE assessed the root cause of both violations as ineffective detective controls — specifically a failure to “identify and correct issues with [Luminant’s] controller frequency response logic and other settings that affect PFR performance.” The RE wrote that the violation posed a minimal risk, observing that “the overall market frequency response in the Texas Interconnection is robust enough to ensure sufficient frequency response [was] available to respond to” frequency events despite the incorrect PFR settings.
Texas RE acknowledged the duration of the infringement, with some units having the wrong PFR value for several years, but wrote in the utility’s defense that the problem might not have been detected because detection requires frequency events that were rare in the area. For example, the RE observed that the last score recorded for Oak Grove 2 was in April 2023, and Castle Gap’s last recorded score was in June 2024. Texas RE also considered Luminant’s “robust” internal compliance program to be a mitigating factor in the penalty determination.
Finally, Texas RE acknowledged that Luminant has experienced prior noncompliance issues with the same requirements, but it determined that these incidents “should not aggravate the penalty” for two reasons. First, those violations were disposed of as compliance exceptions, which are not meant to be used as aggravating factors for a later violation unless it is considered a serious or substantial risk. Second, Texas RE determined that the mitigations for the previous violations would not have prevented the most recent issues because they affected different settings.
Commissioners also approved a separate SNOP concerning violations of NERC’s Critical Infrastructure Protection standards. Details of that SNOP were not made public in keeping with the commission and NERC’s policy against sharing critical energy/electric infrastructure information.
FERC rang out the regulatory year for SPP by accepting the grid operator’s tariff revisions establishing subregions for the cost allocation of future byway projects under its highway/byway methodology.
The Dec. 30 order decouples SPP’s Schedule 9 (zonal rates) and Schedule 11 (highway/byway) transmission pricing zones and creates five larger Schedule 11 subregions of existing zones (ER26-407).
Two-thirds of the cost of byway upgrades (between 100 and 300 kV) will be allocated to the subregion in which they are connected, with the remaining 33% allocated to the SPP footprint. New base plan upgrades larger than 300 kV will be allocated RTO-wide as highway projects.
SPP plans to group its 18 existing transmission pricing zones into five new Schedule 11 subregions: North, Nebraska, Central, Southwest and Southwest. The subregions will replace legacy pricing zones only to allocate costs for future byway facilities under Schedule 11 and will not affect Schedule 9 zonal boundaries or previously approved cost allocations.
The commission found that the RTO’s proposed modifications to the cost allocation for byway facilities “reasonably reflects that the transmission customers within a subregion use and benefit from these facilities.” It said SPP’s technical analyses demonstrate that the zones within each proposed subregion are significantly integrated based on their “complementary import/export patterns, significant inter-zonal connectivity, similar power-flow patterns and other operational interdependencies.”
FERC disagreed with protests filed by the Louisiana, Oklahoma and Texas regulatory commissions that SPP’s proposal was facially deficient and that it had not satisfied its burden under the Federal Power Act because the RTO failed to identify or quantify the proposal’s future cost impacts. The commission said SPP had met its burden to show the tariff changes comply with FERC’s cost-causation principle.
It also was unpersuaded by an assertion by the city of Springfield, Mo., that SPP did not demonstrate how the Regional Cost Allocation Review (RCAR) process would fairly evaluate cost-benefit imbalances under the proposed modifications. The RCAR reviews the highway/byway cost-allocation methodology every six years to analyze the effects on each pricing zone.
SPP’s proposal was approved by its board, state regulators and members in 2025. Several members pushed back over concerns about unreasonable cost shifts. (See “Members Pass Last of HITT’s 2019 Recommendations,” SPP MOPC Briefs: April 15-16, 2025.)
FERC disagreed, finding that the grid operator had “adequately demonstrated” that allocating two-thirds of byway facility costs to its subregion and the remainder on a regional load ratio share basis “allocates the costs in a manner that is at least roughly commensurate with the benefits of these facilities.”
SPP’s proposal was the last recommendation from the Holistic Integrated Tariff Team (HITT), which was created in 2018 to conduct a comprehensive review of the RTO’s cost-allocation model, transmission planning processes, Integrated Marketplace and real-time operations. After a year of discussion, the 15-person HITT published a report with 21 recommendations. (See HITT Shares Draft Report with SPP Stakeholders.)
The tariff change was hung up for several years by work on another HITT recommendation to adopt a policy creating an appropriate balance between cost assessed and value attained from energy and network resource interconnection service products and generating resources with long-term firm transmission service.
Vistra has signed a deal with Cogentrix to buy 5,500 MW of natural gas units in PJM, New England and Texas for $4 billion, the companies announced Jan. 5.
The deal includes three combined cycle plants and two combustion turbine facilities in PJM, four combined cycle facilities in ISO-NE and a cogeneration plant in ERCOT. Vistra is putting up $2.3 billion of cash, $900 million of stock and the assumption of $1.5 billion in debt, minus about $700 million of net present value in tax benefits.
“The Vistra team is excited to announce the acquisition of the Cogentrix portfolio, marking the second opportunistic expansion of our generation footprint over the past year to support our ability to serve growing customer demand in our key markets,” Vistra CEO Jim Burke said in a statement. “Successfully integrating and operating generation assets is a major undertaking, and our talented team continues to demonstrate that it is a core competency of our company.”
The new natural gas generator portfolio will help Vistra meet the growing demand of its customers, Burke said. He added that the company continues to look for additional opportunities to expand supply that meet its “disciplined investment thresholds.”
Cogentrix is owned by the energy-focused private equity firm Quantum Capital Group. The sale represents “substantially all of its portfolio,” Quantum CEO Wil VanLoh said.
“We are excited to become shareholders of Vistra and have much confidence in Vistra’s ability to deliver long-term value through its industry-leading portfolio and operational excellence,” VanLoh said in a statement. “Quantum thanks the Cogentrix team for their partnership and looks forward to seeing the business continue to grow as part of Vistra.”
Two of the plants — the Patriot and Hamilton Liberty combined cycle generators in Pennsylvania — are only majority-owned by Cogentrix, but Vistra is buying 100% ownership in them.
The plants are modern and efficient and add baseload capacity that complements Vistra’s existing units, the company said. The portfolio averages a heat rate of 7,800 Btu/kWh, while the Patriot and Hamilton Liberty plants are just 10 years old and more efficient at 7,000 Btu/kWh.
The capacity is in three of the most attractive and fastest growing markets in the country, and once the deal closes, Vistra’s U.S. fleet will total 50 GW.
The deal needs approvals from FERC, the Department of Justice under the Hart-Scott-Rodino Act and some state regulators. Vistra hopes to close it later in 2026.
The Bonneville Power Administration has executed new long-term wholesale electric power contracts with more than 130 public utility customers under the agency’s Provider of Choice initiative, according to an announcement.
The new 16-year power purchase agreements with Northwest public utility customers were signed throughout the fall and are the product of a four-year effort to get contracts in place before existing agreements expire in 2028, according to a Dec. 23 news release.
“This is a watershed moment for BPA and our ratepayers,” agency Administrator and CEO John Hairston said in a statement. “With these contracts in hand, we have the continuity and certainty necessary to continue building and expanding the value of the federal power and transmission systems that deliver vital, low-cost and reliable electricity to millions of residential, commercial and industrial consumers and serves as a cornerstone of the Pacific Northwest’s economy.”
A recent study by Energy and Environmental Economics (E3) found that accelerated load growth and aging power plant retirements in the Northwest could create a resource gap starting around 1.3 GW in 2026 and expanding to almost 9 GW by 2030. (See 9-GW Power Gap Looms over Northwest, Co-op Warns.)
The news release did not mention the E3 study, but BPA said the contracts would provide a “sturdy financial base for Bonneville as it works to ensure the region is ready to meet the increasing energy demands in the near term and the future.”
With the contracts signed, the agency enters a three-year implementation period to begin power sales in October 2028. The implementation period includes calculating Contract High Water Marks, drafting Resource Support Services contract provisions and standing up associated systems and processes identified in the Provider of Choice (POC) contracts, BPA spokesperson Kevin Wingert told RTO Insider on Jan. 5.
BPA will use the new Public Rate Design Methodology to establish rates under the BP-29 Rate Case expected to launch in fall 2027, according to the news release.
Bonneville delivers power to regional public power customers under contracts executed in 2008. The agreements provided approximately 76% of BPA’s power services’ revenue requirement in 2022, according to a concept paper. (See BPA Preparing to Deliver Power Under New Multiyear Contracts.)
The long-term contracts by statute cannot exceed 20 years, and BPA initiated the POC effort in 2021 to begin contract discussions with stakeholders before agreements expire in September 2028, according to the paper.
POC contracts are for BPA’s preference customers only, and no IOUs have signed an agreement. However, BPA developed the New Resource Rate Block Policy in August 2025, which outlines how an IOU could request service and what an agreement would include, according to Wingert.
The agency has launched other initiatives aimed at meeting the Northwest’s growing energy demand, the Dec. 23 news release noted.
For example, the agency is working to improve the power output for the Columbia Generating Station, a nuclear power plant. The agency said the modifications could result in additional output of approximately 160 MW by 2031.
Other efforts include investments in the Federal Columbia River Power System, such as high-efficiency turbine runners, generator rewinds and two new turbines, which the agency hopes could provide up to 330 aMW of additional energy for BPA customers.
The agency’s Grid Access Transformation initiative aims to make it easier for power producers to access the grid and shorten the construction time of new transmission lines. BPA is investing “up to $25 billion in transmission projects and reinforcements across the Northwest,” according to the news release. (See Utilities Back Some BPA Transmission Updates, Hesitate on Others.)
MISO is re-examining its longstanding policy that forbids stakeholders from recording meetings and is considering the possibility of some form of AI notetaking or transcription.
Counsel Jacob Krause told a Jan. 5 meetup of the Stakeholder Governance Working Group that MISO is investigating “tools” that would create a record of stakeholder meeting content. He promised more details after the RTO gathers its stakeholders’ opinions on the issue. It’s not clear if MISO would allow stakeholders to make their own recordings of meetings.
The grid operator prohibits anyone from recording meetings, save for a few self-recorded workshops throughout the year. In 2024, it banned the use of AI notetaking, and its Stakeholder Relations division has periodically expelled AI bots from meetings.
Multiple stakeholders voiced support for MISO’s re-examination.
Tyler Bergman, a senior manager of Clean Grid Alliance, said granting stakeholders the ability to review meeting discussions after the fact would help stakeholders balance their work and personal lives with MISO’s “very active stakeholder schedule.” He pointed out that CAISO records its meetings and makes the recordings and transcripts publicly available in a temporary archive on its website.
John Liskey, of the Citizens Utility Board of Michigan, said it’s difficult for his fellow members of the consumer advocate sector, including state attorneys general, to keep up with MISO meetings.
“It’s one thing to take notes, but it’s another thing to listen to a recording and really understand the dialogue,” Liskey said.
Mississippi Public Service Commission consultant Bill Booth said “several commissions in the South” would be interested in accessing transcripts of MISO meetings.
“We all take notes, but we don’t capture everything, so transcripts would be helpful,” Booth echoed.
But ITC Holdings’ Cynthia Crane said she has “strong concerns about changing historic practice” at MISO. Crane said conducting meetings with a recording device could have a chilling effect on discussion and lead to self-censoring and diminished participation in discussions. She said stakeholders could develop a “fear of misrepresentation and the use of sound bites” without context.
The Sustainable FERC Project’s Natalie McIntire disagreed that recordings would suppress discussion. She pointed out that MISO’s meetings are already open to the press, and reporters aren’t infallible and can misrepresent someone’s point. McIntire said stakeholders for years have been aware that they could be quoted while expressing their stances in meetings.
Liskey suggested MISO introduce a “trial period” of allowing recorded meetings and see if the practice dampens conversations.
WEC Energy Group’s Chris Plante said there’s perhaps a “middle ground” where, after MISO investigates notetaking tools, it allows summaries of meetings instead of verbatim transcripts. Plante said that way, stakeholders who inadvertently unmute themselves during meetings don’t have their embarrassing gaffes chronicled.
As if to illustrate the point, the teleconference was later interrupted several times by someone speaking in French.
MISO and stakeholders plan to again address the possibility of recording or allowing AI to summarize meetings at the April 20 meeting of the Stakeholder Governance Working Group.
The first time I heard an energy industry official mention the word “flexibility” was back in the early 2010s, when I was a fledgling energy reporter at The DesertSun in Palm Springs, covering the permitting and construction of an 800-MW natural gas power plant to be located north of the city. The Sentinel plant and its eight, 90-foot-tall emission stacks were needed for system flexibility, a representative from CAISO told me.
As more and more variable renewables came online ─ like the hundreds of wind turbines also located north of Palm Springs and the first utility-scale solar projects on federal land east of the Coachella Valley ─ flexible power that could come online quickly was critical, the official told me. And back then, fast and flexible meant natural gas.
Sentinel was a peaker ─ ideally used only to fill gaps in power supply at times of high demand ─ and was licensed to operate only one-third of the time. It could fire up in about 10 minutes, and according to an environmental impact report that I read in detail, could put up to one million tons of carbon dioxide per year into the region’s already polluted air.
(Despite its status as a major resort area ─ and home to one of the country’s largest music festivals ─ the Coachella Valley has notoriously poor air quality, due in part to the hundreds of diesel-powered 18-wheelers rolling through it daily on the Interstate 10 highway.)
CAISO ran its first demonstration projects using energy storage for system flexibility between 2014 and 2016 ─ after I left Palm Springs ─ but the results were impressive. I was in D.C. at the Smart Electric Power Alliance by then and remember another conversation with a contact at CAISO, who told me the storage was faster and more flexible than a natural gas peaker.
Ten years on, California has 17 GW of energy storage online, allowing the state to ride out summer heat waves ─ just one sign that flexibility has gone from marginal to mainstream. It also is a core attribute of the various scenarios and solutions being discussed to meet the snowballing estimates of U.S. electric power demand that drove headlines in the industry and mainstream media in 2025.
K Kaufmann
2026 is going to be all about how to further integrate flexibility as part of a clean, reliable and affordable electric power system. The technology is available, with prices going down and advanced capabilities expanding at speed and scale, powered by artificial intelligence. The lag, as ever, is on the policy and regulatory side.
The questions will be about what kind of new or different market mechanisms and regulatory guidelines will be needed to ensure the U.S. power system can take full advantage of all the different value and revenue streams flexibility can offer.
Specifically, regulators have yet to figure out how to fully integrate and compensate distributed technologies, like storage, which do not fit into traditional categories of supply and demand ─ generation and load, charge and discharge ─ and how these different technologies are rated on the grid.
But the typically glacial pace of regulation ─ with endless pilot projects and decisions often years in the making ─ is no longer tenable. Demand growth, rising electric bills and the need for system reliability and resilience are converging to accelerate the pace of change, with big tech hyperscalers ─ companies like Google building gigawatt-scale data centers ─ pushing all the various envelopes involved.
What is ahead will be exciting, uncomfortable and unavoidable for all stakeholders, including President Donald Trump and his supporters, who, despite all evidence to the contrary, are stubbornly clinging to fossil fuels as the primary solution for all the challenges of demand growth.
The Flex Front 2025
Any discussion of grid flexibility probably should start with a working definition. In grossly oversimplified terms, we know that our electric power system is overbuilt to handle periods of high demand that may occur only a handful of times each year, which means it often is grossly underused. That excess capacity can be optimized with grid-enhancing technologies ─ like advanced conductors and dynamic line ratings ─ which in turn can allow for the flexible integration of different forms of carbon-free generation and storage.
Further, electric power can be “flexed” at all levels of the system, from residential, commercial and utility-scale to distribution and transmission.
That flexibility in and of itself framed new and innovative views of the grid in 2025, beginning with a Duke University study, released in February, suggesting that if data centers were willing to curtail their electric use even .25% of the time, it would open up space on the grid for 76 GW of new generation. A curtailment rate of 1% could mean enough headroom to add 126 GW of new power.
The study has been widely cited, and Tyler H. Norris, its lead author, quickly became a much-sought-after speaker at industry conferences and webinars. In November, Google hired Norris to lead its market innovation and advanced energy initiatives.
Other key developments on the flex front included:
The July 29 virtual power plant demonstration in California: More than 100,000 residential batteries simultaneously discharged for two hours, from 7 to 9 p.m., pumping out 539 MW of electricity, or the equivalent of a mid-sized power plant. An analysis of the demonstration by The Brattle Group concluded that the aggregation of behind-the-meter solar and storage “can deliver reliable, utility-scale capacity at a significantly lower cost than traditional solutions.”
Energy Secretary Chris Wright’s Oct. 23 directive to FERC: Wright proposed new rules for the interconnection of “large loads” ─ that is, data centers ─ which would allow expedited approvals for co-location of centers and generation if power at such facilities could be curtailed or dispatched by a grid operator. FERC received more than 200 comments on Wright’s proposed rules, with hyperscalers in particular opposing any rule that linked expedited interconnection to curtailment controlled by grid operators or utilities.
The Electric Power Research Institute’s DCFlex initiative: Significantly, EPRI launched this new program in 2024, with the goal of developing data centers as flexible grid assets. A heavy-hitting list of project collaborators includes Google, Meta, Microsoft, Nvidia and Schneider Electric, along with major utilities, RTOs and ISOs. An interactive map on the DCFlex website shows that utilities in 41 states already have some kind of flexible load or demand management programs.
Clearly, everyone ─ even Chris Wright ─ knows that change is coming; flexibility will be a critical must-have, and those who are not ready or willing to innovate and invest will be left behind.
Above Politics
The physics, economics and politics of the next few years are well known. Estimates of the amount of new power the United States will need by 2030 increase with almost every new report. Back in February, the Duke University study estimated that data centers alone would drive 65 GW of new demand by 2029.
An ICF report from May called for 80 GW of new power to come online per year for the next 20 years, while in November, Grid Strategies upgraded an earlier estimate of 128 GW needed by 2030 to 166 GW.
The turbines that will power new natural gas plants could take years to deliver due to material and labor shortages and leave consumers vulnerable to the turbulence of natural gas prices. Renewables are cheaper and faster to build ─ and according to interconnection.fyi, still make up about 88% of projects sitting in interconnection queues nationwide ─ but face a virtual obstacle course as the Trump administration, RTOs and some utilities prioritize natural gas and nuclear.
Natural gas and renewables also will require new transmission and streamlined, accelerated permitting, all of which, including new data centers, are likely to face local opposition.
And electric bills are going nowhere but up ─ period. The ICF report estimates that residential rates could rise 15 to 40% by 2030, depending on the region.
Flexibility redefines everything and, again, is available immediately with existing technologies, which will get cheaper and smarter with speed and scale. This is why it will be essential for system evolution at all levels in 2026.
Flexibility turns grid-edge renewables from variable or intermittent to flexible and dispatchable resources that can shave peak demand, as seen in California’s VPP demonstration. Homes, businesses and data centers all can serve as flexible grid assets, which can help cut electric bills and drive behavioral change.
Consumers increasingly will see the value of adopting technologies that combine energy efficiency with flexibility ─ like solar and storage ─ so they can participate in even more sophisticated demand management programs.
In addition, upgrades that make existing transmission and distribution systems more flexible could allow for more distributed renewables, while triggering less local NIMBYism and reducing the need for new fossil-fueled generation.
In other words, flexibility is a no-brainer. It is above politics, and it just makes sense.
Fail and Scale Fast
President Trump notwithstanding, clean energy will continue to grow ─ though at a slower rate ─ in 2026 because it is faster, cheaper, cleaner and more flexible than fossil fuels. But the more significant paradigm shift this year will be toward policies, again at all levels, that promote the adoption of flexible technologies, ensure they are valued and compensated appropriately and accelerate permitting.
While Trump and some major players in the industry frame the current crunch in demand growth as an “energy emergency,” it actually is a long overdue and extremely cool opportunity for the electric power sector to reinvent itself. It has been dragging its feet on a 21st-century makeover, while its customers increasingly move at the blistering speed of AI.
High-tech hyperscalers are setting the pace. They want power, speed and flexibility for their data centers. They have the technology, the experts and the money to invest in system change; they know how to fail and scale fast; and they do not like waiting for regulators or utilities unless they absolutely must.
Interconnection policies have become the front line of change, where expedited approvals for projects turn on their ability and willingness to flex their power. Texas pioneered this kind of “conditional interconnection,” now codified via SB6, signed into law in June. California followed suit in August with its Limited Generation Profiles policy, which limits the amount of power distributed projects can export to the grid at times of system stress.
What is particularly exciting here is the implicit acceptance of flexibility as a central attribute of the grid and how that in and of itself redefines reliability and resilience.
PJM will provide the acid test of this approach as it works to comply with FERC’s recent order requiring an overhaul of the RTO’s interconnection policies for new generation co-located with data centers. In particular, the order requires PJM to adopt rules and the associated tariffs for co-located generation that can self-curtail or flex its demand on an interim or regular basis. (See FERC Directs PJM to Issue Rules for Co-locating Generation and Load.)
Any final rules from FERC promoting flexible interconnection should send a signal to other grid operators, states and utilities. Wright’s directive called for the federal regulators to complete work on his proposed rules by April, which would be warp speed for the commission, especially given the many concerns raised by stakeholders.
Demand management also is going to move fast. With Tyler Norris on board, we can expect to see new initiatives in this area from Google, which has signed flexible demand agreements with the Tennessee Valley Authority and Indiana Michigan Power. Meanwhile, Amazon is promoting grid-enhancing technologies as a way to get more renewables online.
Building on California’s demonstration, 2026 will see a ramp in VPPs. A recent article in Energy Storage News details three new VPPs being launched by a range of developers and utilities in California, as well as in Texas, Washington, Arizona and the Tennessee Valley. One example is a new partnership between software developer Leap and independent power producer Enel North America that aims to connect commercial distributed resources to utility demand management programs.
Why is any of this important? As flexibility becomes the new normal, it makes us think about electric power differently. It redefines our relationship to how we produce it, how we use it and what we can do with it. It makes us aware that we as consumers have an active role to play here, and that we can do more than complain about rising electric bills and then pay them.
Let us also remember that when we talk about flexibility and renewables, we are talking about climate change and reducing greenhouse gas emissions, whether we use the actual words. We have shifted from an environmental to a practical, business case for climate action, which is equally if not more effective.
Coming full circle, in 2024, the Sentinel plant was approved for a 17.18-MW, 34.36-MWh battery storage system to provide black start capability, so the plant can restart itself even if it goes offline.
When peakers need extra flexibility, we are way past the point of no return; 2026 is going to be a good year.
