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New Sensor Data Provides More Insight Into What May Have Caused California’S Eaton FireData from a software and sensor company is providing additional insight into what may have happened when the recent Eaton fire broke out in Southern California.
Whisker Labs, a company that deploys sensor technology meant to help predict and prevent wildfires and detect electrical faults, has released new data from the day the fires began, the New York Times reports. The company purports its data shows that two faults occurred on transmission lines near Altadena on January 7, just before the Eaton fire began in the same area.
The first fault was detected at 6:10 PM, and another one was detected three seconds later. The disruptions were felt states away in Oregon and Utah through thousands of sensors, according to Whisker Labs. Whisker Lab’s sensors are installed in homes and can help measure and detect power and arc faults along the grid.
“We looked at this one — it was like, Holy cow,” Bob Marshall, co-founder and chief executive of Whisker Labs, told the New York Times. “This is a transmission-scale event. Any time something happens on the grid and we see a fault at exactly the same time on many, many sensors, then it is a fault on the utility grid.”
Does Whisker Labs sound familiar? Read our feature on how the company’s smart sensors have detected “noisy power” outside of IEEE standards that could be costing ratepayers money.
Southern California Edison (SCE) on Monday reported a fault on a power line connected miles away from ones located near the origin of the Eaton Fire, the deadly blaze that ignited outside of Los Angeles on Jan. 7 and killed at least 17 people.
In its new filing, Edison reported that the fault occurred at 6:11 p.m. While those lines that experienced the fault do not traverse Eaton Canyon, they are connected to the system, which did experience a surge, the utility reported.
The timing of the faults seems to line up with security footage from a nearby gas station that was presented in a court hearing in a case filed by attorneys for a homeowner whose property was destroyed in the fire. The attorneys say the video shows arcing and electrical sparking on a transmission tower in Eaton Canyon just before the wind whipped the fire into a fast-moving and destructive blaze.
The attorneys alleged SCE’s equipment sparked the fire, pointing to a different video taken during the fire’s early minutes that shows large flames beneath electrical towers.
Attorneys for Altadena resident Evangeline Iglesias argued that, together, the fault and gas station video provides “evidence that SCE’s equipment in Eaton Canyon was the source of the initial ignition, and there is a near-certainty that physical evidence of the cause exists somewhere along the SCE transmission lines that run parallel to the line on the tower that erupted in flame.”
Video and photos taken by residents also captured flames beneath SCE’s electrical towers in the Eaton Canyon area in the early minutes of the fire. One resident said he heard a loud pop at the outset of the conflagration.
The Eaton Fire was one of two massive and deadly blazes that sparked on Jan. 7 amid hurricane-force winds that whipped across the parched Los Angeles region. At least 28 people have died and firefighters have continued battling the blazes for weeks. The Eaton Fire is now nearly contained, meaning firefighters almost have it totally surrounded, as the region gets its first rain in months.
Iglesias’ attorneys have accused the utility of destroying evidence. A judge last week ordered SCE to preserve evidence in the area, concerned that the utility is discarding equipment that may hold clues to the fire’s origin.
SCE’s attorneys say the company has preserved evidence in the area where the fire originated as its crews work to restore power to about 2,000 homes in Altadena that are still dark.
In an earlier filing to the CPUC, SCE reported two days after the fire started that it had not received any suggestions that its equipment was involved in the ignition.
“Preliminary analysis by SCE of electrical circuit information for the energized transmission lines going through the area for 12 hours prior to the reported start time of the fire shows no interruptions or electrical or operational anomalies until more than one hour after the reported start time of the fire,” the utility reported.
This article contains reporting from the Associated Press.powerplant
Jan 30, 2025
Power Grid International
National Grid’S Bridget Powers Beggs On ‘Right-Sizing’ Distribution Systems And The Economic, Societal Value Of DermsDecarbonization goals are leading a transition towards higher penetrations of renewables and electrified loads, and while the technical merits of distributed energy resource management systems (DERMS) have received significant attention in recent years, the economic and societal values of DERMS-enabled applications are still being discerned.
Bridget Powers Beggs, an engineer for National Grid’s Integrated Planning and Solutions team, will speak on both of these issues facing utilities at DTECH (formerly known as DISTRIBUTECH) March 24-27, 2025 in Dallas, Texas.
Powers Beggs will participate in two sessions sessions:
“These are both important topics for utilities, as meeting the challenges of both electrification and decarbonization will require unprecedented investment in both traditional infrastructure and flexibility solutions,” Powers Beggs said. “Decision frameworks and benefit-cost models for how to evaluate these investments on a level playing field is therefore critical to ensure affordability for our customers in both the near and long-term.”
This session will present methodologies for assessing the value streams enabled by DERMS to support utility investment decisions and cost-recovery filings. DERMS applications considered include supporting flexible interconnection agreements, non-wires alternatives, and DER grid services. Utility representatives from Xcel, PG&E, and National Grid will discuss real-world case studies that illustrate these concepts in practice.
Session participants will gain a comprehensive understanding of how to evaluate the benefits of DERMS and apply these insights to optimize grid management and investment strategies.
A robust electric distribution system that is “right-sized” with modern capabilities is needed to achieve increasing customer expectations in a safe, reliable, and affordable manner. As the distribution system rapidly evolves, novel planning, design, and operating processes are also needed to proactively identify and justify the needs and designs of the future.
In this panel, Dominion Energy, National Grid, Southern California Edison (SCE), and EPRI will share their approaches to handling mass electrification and renewable growth, including the strengths, weaknesses, opportunities, and threats of each solution. Dominion Energy will discuss the benefits and challenges associated with its 34.5 kV distribution system, and National Grid will speak on capacity solutions for legacy 4 kV systems.
In addition, SCE and EPRI will present key findings from the recent grid architecture project. In this project, EPRI conducted an in-depth review of unique grid architectures and designs globally to uncover the best practices and methods established by various regions. It highlighted, on a global scale, the innovative and forward-thinking methods being adopted for future grid developments as well as case studies for grid transformations at various levels of transmission and distribution.
Powers Beggs is currently an area engineer on National Grid’s New York Distribution Planning and Asset Management team. In their time at National Grid they have worked on the Integrated Planning and Solutions, Future of Electric, and Grid Modernization Solutions teams on a variety of projects, including leading regulatory filings, developing benefit cost analyses for grid modernization and Distribution System Operator (DSO) investments, and updating planning criteria, practices and processes for electrification.
Attending DISTRIBUTECH? Don’t miss these other great sessions!
This list will be updated as more sessions are previewed.powerplant
Jan 29, 2025
Power Grid International
Data Centers Fuel Energy Debates In Virginia As Lawmakers Seek Ratepayer Protectionsby Leah Small, Virginia Mercury
With data centers placing an ever-growing strain on the grid, Virginia legislators are introducing measures to ensure residents don’t bear the brunt of rising energy costs caused by the booming industry. However, the proposals are facing stiff resistance.
One bill targeting large electric load businesses has been tabled, while another initially singling out data centers was amended. Lobbyists for the data center industry have pushed back, warning that these measures could hinder economic growth and unfairly single out a sector that, according to Gov. Glenn Youngkin, contributes $9.1 billion to Virginia’s gross domestic product.
Legislators also renewed, but once again failed in a push to shed some light on the proceedings of PJM — the nation’s largest regional power transmission organization. Utility companies, such as Dominion, are voting members of the organization, whose decisions on major transmission projects directly impact costs passed on to customers.
Lawmakers are faced with balancing the economic opportunities brought by data centers with protecting consumers and meeting clean energy mandates, in the face of rising energy production and transmission costs, says Del. Irene Shin, D-Fairfax.
“Virginia has enjoyed relatively flat load growth, and I think right now we’re in that moment of hockey sticking, primarily driven by the data center industry,” Shin says. “We’re looking out for our constituents and making sure they’re paying their fair share and not more than that. It is up to industry to pay their fair share of what we know are the incredibly exorbitant costs to service data centers.”
Shin introduced House Bill 2084, which directs the State Corporation Commission (SCC) to review the rate classifications of phase I and phase II public utilities to ensure fairness to all ratepayers. The bill’s original version, which explicitly required Dominion Energy and Appalachian Power to establish separate rate classifications for data centers, was met with fierce opposition in subcommittee.
The revised bill now leaves the decision about reclassifying customers entirely to the SCC, with no specific mention of data centers.
While data centers are currently paying their fair share under existing utility rate structures, their rapidly growing energy demand “will likely increase system costs for all customers,” according to a report by the Joint Legislative Audit and Review Commission (JLARC). The report suggests that creating separate rates for data centers could shield other customers from rising costs.
Without such measures, the JLARC study projects that utility bills for the average residential customer could increase by as much as $444 annually by 2040, excluding inflation.
Virginia leads the nation in the number of operational data centers. The industry is rapidly expanding in neighboring states. Last year, Duke Energy in North Carolina introduced new rate structures for data centers to address rising power demands.
Before references to data centers were removed from House Bill 2084 last week, Kate Smiley, a spokesperson for the Data Center Coalition, argued that decisions on raising rates for data centers should begin with the SCC, not legislators. She also contended that creating separate rates for data centers would be discriminatory.
“Rate classes should ultimately be established based on load characteristics rather than the business in which the customer is engaged,” Smiley said. “These costs caused by a rate class are driven by its aggregate load shape, the volume of power it consumes, the number of customers served — not the business end use.”
Del. Candi Mundon-King, D-Prince William, pushed back on the notion of discrimination against data centers.
“This idea of poor data centers being discriminated against is really something we should shy away from,” she said. “We have a responsibility to be great partners with people who are investing in the commonwealth, but our first responsibility is to the safety and wellbeing of citizens of the commonwealth.”
House Bill 2027, which failed in a subcommittee vote earlier this month, sought to require new facilities with power loads of 100 megawatts or more — amended from the original threshold of 25 megawatts — to obtain a certificate to operate.
Glenn Davis, director of the Virginia Department of Energy and a former Republican state senator from Virginia Beach, opposed the legislation, arguing it would unnecessarily slow the permitting process handled by the SCC and create unfair competition among businesses for power capacity.
“[The SCC is] going to be picking winners and losers,” Davis said. “How do they decide between two 100 megawatt facilities when only 100 megawatts are available?”
Del. Joshua Thomas, D-Prince William, who sponsored the legislation, cited the JLARC report to emphasize the urgency of placing limits on power consumption. He warned that without constraints, Virginia faces “an unconstrained load environment where we have an 183% increase of load over the next few decades, which is unsustainable.”
House Bill 2003, which aimed to increase transparency in the voting process for PJM, the regional organization coordinating power transmission and generation for Virginia and much of the eastern U.S., failed in committee last week on a 10-12 vote.
The legislation would have required PJM to publish an annual report detailing the committee votes of its public utility members and to provide a statement explaining how each vote served the public interest.
These votes have significant implications, including determining market rules and the approval of large-scale transmission projects — factors that directly impact electric bills. For example, in 2022, a PJM committee rejected a proposal to freeze prices during periods of high electricity cost, but there was no public record on how utility companies voted.
“As our own energy needs are growing with data centers, rate payers deserve to know that the rate they are paying for their energy needs is not subsidizing large industry,” said Del. Amy Laufer, D-Albemarle, who sponsored the bill.
Laufer drew parallels to the General Assembly’s recent move to live stream and record subcommittee votes, emphasizing the need for transparency at all decision-making levels.
“PJM does publish the upper-level votes, but we know that the policies and proposals voted on at the lower-level meetings have a large impact on what happens at the upper-level meetings, which directly impact 65 million ratepayers,” Laufer said.
Christine Noonan, a lobbyist representing Dominion Energy, expressed concerns that publishing committee votes could discourage open discussions with PJM.
“We want to ensure that this quest for transparency doesn’t hamper collaboration,” Noonan said, adding that any transparency requirements “should apply equally to all entities that either generate [power] or have [power] transmission in the commonwealth.”
Virginia Mercury is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence. Contact Editor Samantha Willis for questions: [email protected].powerplant
Jan 28, 2025
Power Grid International
California Utility Reports Fault On Power Line Miles Away From Origin Of Deadly Eaton FireBy JASON DEAREN Associated Press
GLENDALE, Calif. (AP) — Southern California Edison on Monday reported a fault on a power line connected miles away from ones located near the origin of the Eaton Fire, the deadly blaze that ignited outside of Los Angeles on Jan. 7 and killed at least 17 people.
Edison says that there is still no evidence that its equipment caused the blaze, which has destroyed more than 9,000 structures in and around the community of Altadena. The official investigation into the fire’s cause has not been completed.
The utility’s new filing with the California Public Utilities Commission comes on the same day as a court hearing in a case filed by attorneys for a homeowner whose property was destroyed in the fire. The attorneys allege the utility’s equipment sparked the fire, pointing to video taken during the fire’s early minutes that shows large flames beneath electrical towers.
The attorneys have now introduced new video they say shows arcing and electrical sparking on a transmission tower in Eaton Canyon just before the wind whipped the fire into a fast-moving and destructive blaze. They say the video came from security footage of a gas station.
The Eaton Fire was one of two massive and deadly blazes that sparked on Jan. 7 amid hurricane-force winds that whipped across the parched Los Angeles region. At least 28 people have died and firefighters have continued battling the blazes for weeks. The Eaton Fire is now nearly contained, meaning firefighters almost have it surrounded, as the region gets its first rain in months.
In its new filing, Edison reported that the fault occurred at 6:11 p.m. While those lines that experienced the fault do not traverse Eaton Canyon, they are connected to the system, which did experience a surge, the utility reported.
“Preliminary analysis shows that, because SCE’s transmission system is networked, the fault on this geographically distant line caused a momentary and expected increase in current on SCE’s transmission system, including on the four energized lines (in the fire area),” SCE’s filing said. “The current increase remained within the design limits and operating criteria for these circuits and, as intended, did not trigger system protection on these lines.”
Attorneys for Altadena resident Evangeline Iglesias argued that, together, the fault and gas station video provide “evidence that SCE’s equipment in Eaton Canyon was the source of the initial ignition, and there is a near-certainty that physical evidence of the cause exists somewhere along the SCE transmission lines that run parallel to the line on the tower that erupted in flame.”
Video and photos taken by residents also captured flames beneath Edison’s electrical towers in the Eaton Canyon area in the early minutes of the fire. One resident said he heard a loud pop at the outset of the conflagration.
Kathleen Dunleavy, a spokesperson for Southern California Edison, said the company received the footage of the gas station video from The New York Times on Saturday night and contacted authorities to ensure they had the video as well. She said it was premature for them to comment on the footage as experts investigated what caused the blaze.
“As of today, January 26, no one knows what caused the Eaton Fire,” Dunleavy said in an email Sunday. “Our investigation is ongoing, and we will continue our longstanding commitment to transparency.”
Iglesias’ attorneys have accused the utility of destroying evidence. A judge last week ordered Edison to preserve evidence in the area, concerned that the utility is discarding equipment that may hold clues to the fire’s origin.
SCE’s attorneys say the company has preserved evidence in the area where the fire originated as its crews work to restore power to about 2,000 homes in Altadena that are still dark.
In an earlier filing to the CPUC, Edison reported two days after the fire started that it had not received any suggestions that its equipment was involved in the ignition.
“Preliminary analysis by SCE of electrical circuit information for the energized transmission lines going through the area for 12 hours prior to the reported start time of the fire shows no interruptions or electrical or operational anomalies until more than one hour after the reported start time of the fire,” the utility reported.
This assertion was repeated in the utility’s Monday filing.powerplant
Jan 28, 2025
Power Grid International
Big Tech Wants To Plug Data Centers Right Into Power Plants. Utilities Say It’S Not FairBy MARC LEVY Associated Press
HARRISBURG, Pa. (AP) — Looking for a quick fix for their fast-growing electricity diets, tech giants are increasingly looking to strike deals with power plant owners to plug in directly, avoiding a potentially longer and more expensive process of hooking into a fraying electric grid that serves everyone else.
It’s raising questions over whether diverting power to higher-paying customers will leave enough for others and whether it’s fair to excuse big power users from paying for the grid. Federal regulators are trying to figure out what to do about it, and quickly.
Front and center is the data center that Amazon’s cloud computing subsidiary, Amazon Web Services, is building next to the Susquehanna nuclear plant in eastern Pennsylvania.
The arrangement between the plant’s owners and AWS — called a “behind the meter” connection — is the first such to come before the Federal Energy Regulatory Commission. For now, FERC has rejected a deal that could eventually send 960 megawatts — about 40% of the plant’s capacity — to the data center. That’s enough to power more than a half-million homes.
That leaves the deal and others that likely would follow in limbo. It’s not clear when FERC, which blocked the deal on a procedural ground, will take up the matter again or how the change in presidential administrations might affect things.
“The companies, they’re very frustrated because they have a business opportunity now that’s really big,” said Bill Green, the director of the MIT Energy Initiative. “And if they’re delayed five years in the queue, for example — I don’t know if it would be five years, but years anyway — they might completely miss the business opportunity.”
The rapid growth of cloud computing and artificial intelligence has fueled demand for data centers that need power to run servers, storage systems, networking equipment and cooling systems.
That’s spurred proposals to bring nuclear power plants out of retirement, develop small modular nuclear reactors and build utility-scale renewable installations or new natural gas plants. In December, California-based Oklo announced an agreement to provide 12 gigawatts to data center developer Switch from small nuclear reactors powered by nuclear waste.
Federal officials say fast development of data centers is vital to the economy and national security, including to keep pace with China in the artificial intelligence race.
For AWS, the deal with Susquehanna satisfies its need for reliable power that meets its internal requirements for sources that don’t emit planet-warming greenhouse gases, like coal, oil or gas-fueled plants.
Big Tech also wants to stand up their centers fast. But tech’s voracious appetite for energy comes at a time when the power supply is already strained by efforts to shift away from planet-warming fossil fuels.
They can build data centers in a couple years, said Aaron Tinjum of the Data Center Coalition. But in some areas, getting connected to the congested electricity grid can take four years, and sometimes much more, he said.
Plugging directly into a power plant would take years off their development timelines.
In theory, the AWS deal would let Susquehanna sell power for more than they get by selling into the grid. Talen Energy, Susquehanna’s majority owner, projected the deal would bring as much as $140 million in electricity sales in 2028, though it didn’t disclose exactly how much AWS will pay for the power.
The profit potential is one that other nuclear plant operators, in particular, are embracing after years of financial distress and frustration with how they are paid in the broader electricity markets. Many say they have been forced to compete in some markets against a flood of cheap natural gas as well as state-subsidized solar and wind energy.
Power plant owners also say the arrangement benefits the wider public, by bypassing the costly buildout of long power lines and leaving more transmission capacity on the grid for everyone else.
A favorable ruling from FERC could open the door to many more huge data centers and other massive power users like hydrogen plants and bitcoin miners, analysts say.
FERC’s 2-1 rejection in November was procedural. Recent comments by commissioners suggest they weren’t ready to decide how to regulate such a novel matter without more study.
In the meantime, the agency is hearing arguments for and against the Susquehanna-AWS deal.
Monitoring Analytics, the market watchdog in the mid-Atlantic grid, wrote in a filing to FERC that the impact would be “extreme” if the Susquehanna-AWS model were extended to all nuclear power plants in the territory.
Energy prices would increase significantly and there’s no explanation for how rising demand for power will be met even before big power plants drop out of the supply mix, it said.
Separately, two electric utility owners — which make money in deregulated states from building out the grid and delivering power — have protested that the Susquehanna-AWS arrangement amounts to freeloading off a grid that ordinary customers pay to build and maintain. Chicago-based Exelon and Columbus, Ohio-based American Electric Power say the Susquehanna-AWS arrangement would allow AWS to avoid $140 million a year that it would otherwise owe.
Susquehanna’s owners say the data center won’t be on the grid and question why it should have to pay to maintain it. But critics contend that the power plant itself is benefiting from taxpayer subsidies and ratepayer-subsidized services, and shouldn’t be able to strike deals with private customers that could increase costs for others.
FERC’s decision will have “massive repercussions for the entire country” because it will set a precedent for how FERC and grid operators will handle the waiting avalanche of similar requests from data center companies and nuclear plants, said Jackson Morris of the Natural Resources Defense Council.
Stacey Burbure, a vice president for American Electric Power, told FERC at a hearing in November that it needs to move quickly.
“The timing of this issue is before us,” she said, “and if we take our typical five years to get this perfect, it will be too late.”
GO DEEPER: Access to power has become the key driver of AI and data center growth, prompting the need for new solutions among utilities, developers and other stakeholders. This demand growth will test grid reliability, requiring new ways of collaboration and policy structures.
DTECH Data Centers and AI, taking place May 27-29 in San Jose, California, lives at this intersection of energy and digital infrastructure, exploring the strategies necessary to navigate power constraints, project delays, and the increasing demand for sustainable, flexible solutions.
Sign up now to be notified when registration opens!powerplant
Jan 27, 2025
Power Grid International
Louisiana Pays More For Electricity From One Of The Least Reliable Grids, Audit Findsby Wesley Muller, Louisiana Illuminator
Louisiana residents pay much higher electricity bills than the national average and live with one of the least reliable electric grids in the country, according to a new report from the Louisiana Legislative Auditor’s Office.
The report, titled “Louisiana’s Electric Profile,” details the findings of an in-depth analysis on the generation, consumption and regulation of electricity, including problems affecting the state’s electric grid. It found that, among other things, Louisiana is one of the least energy efficient states with one of the most unreliable electric grids in the nation.
The effects have fallen largely on Louisiana residents, who consume more electricity than almost any other state and pay higher-than-average electric bills.
Also, its power grid experiences the highest number and longest duration of power outages in the southern region — even after excluding service interruptions caused by severe weather, according to the report.
The scope of the analysis covers 2010-23, though some information extends through 2024.
The Louisiana Public Service Commission, which regulates the state’s electric grid and most of its utility companies, served as one of the primary sources of information for the audit. The report also included certain data from municipally-owned electric utilities that fall outside the LPSC’s jurisdiction.
While some of the information has been the subject of previous news reports, the document stands out as a comprehensive assessment of the various issues surrounding the state’s power grid without venturing into the highly technical aspects of the energy sector that is typical of discussions involving the LPSC.
“I know others will say the technical stuff is needed, but it doesn’t gloss over the fact we haven’t diversified” power sources to generate electricity in Louisiana, Public Service Commissioner Davante Lewis said.
The report highlights Louisiana’s heavy reliance on natural gas to generate electricity. The state’s generation portfolio, which covers all electric utilities in Louisiana, was approximately 72% natural gas, 20% nuclear and 5% coal as of 2023. The remaining 3% comes partly from petroleum and renewables.
Louisiana is one of only a few states with such a heavy reliance on natural gas power generation, which is susceptible to large-scale failures during extreme weather, according to the report.
Both the frequency and duration of power outages in Louisiana have increased significantly from 2013-23 even without “major event days” such as storm-related outages and public safety shutoffs. Excluding all major events, the frequency of outages in the state increased 14.3% and the average duration of those outages increased 50%.
The average duration of outages in Louisiana, including those during storms and other major events, jumped 76.4%, from 5.5 hours in 2013 to 9.7 hours in 2023, with the largest spike occurring from 2019 to 2020.
The state’s outage frequency worsened from 1.4 to 1.6 on an index with a national average of 0.9, a figure that’s remained largely steady since 2013.
Asked about the report’s conclusions on grid reliability, Entergy Louisiana agreed severe weather affects reliability and costs but also mentioned Louisiana’s geography as a unique challenge.
“Louisiana is exposed to many natural risks that other states in the Southeast are not prone to,” spokesman Brandon Scardigli said. “Terrain in Louisiana, especially in south Louisiana, where our population centers are located, consistently challenges electric reliability with poles being set in marshes and infrastructure exposed to dense vegetation with multiple growing seasons. Louisiana also has frequent and intense lightning and severe thunderstorms. Simply put, Louisiana is not the same as the states that surround it, ecologically or geographically.”
Scardigli said the company’s reliability is among the best in the state and surpassed the LPSC’s targets for 2023, the most recent available. Also, Entergy recently invested $2 billion in grid hardening measures, which have already seen measurable success in recent storms such as Hurricane Francine, he said.
Utility companies and politicians have often said Louisiana has some of the lowest retail prices of electricity in the country. Public Service Commissioner Eric Skrmetta even mentioned it during his nationally-televised statement at the Republican National Convention last July.
However, those low prices have not equated to lower electric bills for Louisiana residents and businesses, which pay more on average than the rest of the nation, the auditor’s report states.
For residents, particularly, the average monthly electric bill was the 16th highest in the nation in 2023 at roughly $143 per month, according to the report. The average national monthly bill was $137, according to the U.S. Energy Information Administration.
It is not so much the electricity rates that are driving high power bills. Rather, as the report makes clear, it is the high consumption of electricity and inefficiency that Louisiana customers are paying for.
The industrial sector comprises less than 1% of the customer base for electricity but uses the largest share, 42%, of the power generated in the state. Even so, the industrial price of electricity in Louisiana is nearly the same as it was in 2013, the report shows.
When asked about this, Lewis said many of the state’s heavy industrial plants build or purchase their own on-site generators and connectors. This allows them to avoid some of the cost inefficiencies and reliability issues that affect the residential and commercial sectors, he said.
The report also notes Louisiana residents use the most electricity per capita in the nation. The state also ranks second behind Alaska for the highest rate of total energy consumption across all sectors, according to federal data.
“Best practices show that, although maintaining reasonable rates is a priority for all regulators, affordable energy costs cannot be addressed by low rates alone,” the report states.
In an email Thursday, Entergy agreed with some of the auditor’s conclusions regarding Louisiana’s climate and inefficiency issues as major cost drivers.
“Residential electricity costs are driven by Louisiana’s hot summers and older, less energy efficient homes,” Scardigli said.
Over the past three years, several of the state’s utility companies have taken steps to diversify their generation portfolios, particularly with renewable energy. Collectively, the utilities have provided a seven-fold increase in their solar generation from 2020 to 2023.
On average, utility-scale solar and onshore wind are the cheapest of all energy sources in the U.S., even without including subsidies. They have consistently been so for several years, according to annual studies from the financial firm Lazard.
SWEPCO has been importing wind-generated power from other states and has plans for a solar facility in Caddo Parish. Entergy Louisiana received LPSC approval last year to add 3 gigawatts of solar to its portfolio.
The auditors point to low grid reliability, climate, natural disasters and poverty as some of the factors behind energy inefficiency in Louisiana. They also point out that the LPSC has since taken steps to address the problem with a recent adoption of a statewide energy efficiency program that will take effect Jan. 1, 2026.
The report lists a number of things the state could do to improve its electricity profile such as building new transmission lines and decentralizing power generation with initiatives such as community solar gardens. It also highlights the various regulatory inefficiencies that have bogged down innovation.
The auditors recommend the LPSC improve its staff turnover rate, which was 19% last year, and try to fill the 17 staff vacancies it had last year. The audit also points out Louisiana law doesn’t require its public service commissioners to have any relevant educational or industry experience to qualify for election.
“As a result, newly-elected commissioners may face steep learning curves that make it more challenging for them to lead on timely regulatory issues,” the report states.
Louisiana Illuminator is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Louisiana Illuminator maintains editorial independence. Contact Editor Greg LaRose for questions: [email protected].powerplant
Jan 24, 2025
Power Grid International
Once An Engineering Marvel, Two-Thirds Of This Concentrated Solar Power Plant Will Shut Down After A California Utility Pulled Two Of Its Ppas“I met a traveler from an antique land,Who said—“Two vast and trunkless legs of stoneStand in the desert… Near them, on the sand,Half sunk a shattered visage lies, whose frown,And wrinkled lip, and sneer of cold command,Tell that its sculptor well those passions readWhich yet survive, stamped on these lifeless things,The hand that mocked them, and the heart that fed;And on the pedestal, these words appear:My name is Ozymandias, King of Kings;Look on my Works, ye Mighty, and despair!Nothing beside remains. Round the decayOf that colossal Wreck, boundless and bareThe lone and level sands stretch far away.”
Towering 450 feet above the California desertscape, the Ivanpah Solar Electric Generating Facility was once, not so long ago, a monument to man’s ingenuity.
When it was dedicated in 2014 (a ceremonious occasion attended by a whos-who list that included the active Energy Secretary), the 392-megawatt (MW) Mojave Desert project was the world’s largest concentrated solar power (CSP) facility, nearly doubling the amount of solar thermal energy produced in the United States. A $1.6 billion Department of Energy-financed darling, Ivanpah Solar was among the first projects of its ilk to provide electricity to U.S. utility customers, opening a door that has since been kicked down.
And it may soon be a husk of its former self.
Operator NRG Energy plans to shut down two-thirds of the Ivanpah Solar CSP plant after Pacific Gas and Electric (PG&E) decided to terminate two power purchase agreements (PPAs) with the facility to save ratepayers money.
In 2009, PG&E contracted about 250 MW from Ivanpah units 1 and 3, signing 30-year PPAs with BrightSource Energy that were supposed to run through 2039. The financial terms of the agreements were redacted in the utility’s public filing and are considered confidential, but the California Public Utilities Commission (CPUC) clearly thought PG&E was getting a decent enough deal at the time, signing off on the PPAs despite the fact that they had to be significantly adjusted to “accommodate significant changes to the project.”
PG&E asserted in its filing with the CPUC that the amended Ivanpah PPAs were still comparable to other procurement options it received in its 2009 RPS solicitation and even brought in an independent evaluator (IE) to review the altered deals.
“While the IE was unable to validate all the cost inputs and assumptions for the projects, the IE concluded that the amended PPAs appear reasonable in light of the modifications that were necessary to facilitate permitting and financing. The IE also concluded that the all-in costs of the amended Ivanpah PPAs are reasonable when compared to other RPS procurement opportunities including PG&E’s most recently conducted RPS solicitation,” reads part of PG&E’s filing, confirming the utility’s assertions.
In 2021, the CPUC instructed California’s investor-owned utilities to begin a multi-year process of evaluating their energy supply portfolios. Then in 2023, Ivanpah’s current owner, Solar Partners, offered PG&E the opportunity to terminate the Ivanpah Solar power purchase agreements.
Ultimately, PG&E determined nixing the deals would save its customers money compared to keeping them through their original terms.
The PPAs simply didn’t stand the test of time. Ivanpah Solar was built in an era when developers were investing in all sorts of clean energy projects in a “creative destruction” sort of mindset to figure out what worked and what didn’t. The goal was to find efficient and affordable technologies to reduce the need for greenhouse gas-emitting fossil fuels, and it was obvious from the start that not all technologies would prove equally cost-effective.
“It was really all hands on deck,” recalled PG&E senior director of commercial procurement Don Howerton. “The climate crisis was becoming clear. The Southwest United States had been in a megadrought for more than a decade. Heat waves had intensified. Wildfires had grown in number and size.”
In an effort to comply with California’s Renewables Portfolio Standard, PG&E became a big buyer of renewable energy. The utility invested in and contracted for renewable generation of all ilks- including solar photovoltaic, hydroelectricity, wind, biomass, and geothermal. The utility figured that adding concentrated solar power would diversify PG&E’s energy portfolio while supporting new technologies. The tech had proven to work on a smaller scale in Europe and various private companies were investing in large-scale U.S. endeavors at the time.
But in the end, solar PV won the war. Solar’s affordability is simply unmatched, and PG&E would rather admit that now than answer for charging ratepayers an unfair sum through 2039.
“It’s so important to support investment in different projects as we look to solve climate challenges,” PG&E’s Howerton added. “It’s not clear in the early stages what technologies will work best and be most affordable for customers. Solar photovoltaic panels and battery energy storage were once unaffordable at large scale. Today, after years of sustained investment and improvement, those technologies provide thousands of megawatt hours of clean electricity for PG&E customers.”
If the move is approved by the California Public Utilities Commission (CPUC), PG&E will stop receiving power from the plant in 2026. Unit 1 and Unit 3 of Ivanpah will cease operations in response and NRG will begin decommissioning the units. Unit 2 has a PPA with another major California utility, Southern California Edison, and is expected to remain in service.
NRG says affected employees will be able to transfer to other open positions within the company.
PG&E says this decision will not affect its compliance with California’s renewables mandates, insisting it continues to meet its state obligations and is on track to continue to meet more aggressive renewables mandates.
“In the coming years, we expect an even more efficient and affordable market for clean energy,” Howerton said. “We’re proud of our investments in renewables. We look forward to continuing to support technologies that benefit our customers through lower costs and a cleaner environment.”
Originally published in Renewable Energy World.powerplant
Jan 23, 2025
Power Grid International
Redefining The Utility-Customer Relationship In The Energy TransitionAs the energy landscape continues to shift, utilities are finding themselves transforming. The traditional utility-customer relationship, typically an exchange of electricity for payment, is evolving into something much more dynamic.
Jaspreet Singh, executive vice president of advanced technology and chief innovation officer at OATI, described this shift at the OATI Energy Conference in Las Vegas.
“The energy transition is creating very interesting challenges for the utility as well as the customers,” Singh observes. He argues that customers are no longer just consumers of energy – many are becoming “prosumers,” actively generating energy through solar panels, storing it in batteries, and participating in grid operations. “Utilities are looking at their customers not just as the ones they are providing service to, but also as the ones they can get services from,” Singh asserts.
Singh believes in the importance of getting prosumers participating in the grid in an effort to improve efficiency and resilience.
“Utilities need to make systems available for consumers and prosumers so they can participate in programs that help the utility, while also receiving performance incentives and becoming part of the solution,” he said.
Utilities now need configurable and scalable tools to meet their growing and diverse needs. Singh recalled an example involving New York’s Con Edison: when Con Edison approached OATI to develop an aggregator portal, the company prioritized seamless integration with the utility’s brand.
“It was very clear that the Con Ed brand had to follow from A to Z in the customer journey,” Singh recalled. The end result, he says, was a portal that delivered a consistent user experience while enabling customer onboarding and participation.
As a technology company, OATI has the challenge of delicately weighing the balance between innovation and reliability. “There has to be a right mix of new technology and proven technology,” Singh suggests. This includes introducing new tools like AI and machine learning to help utilities meet their goals, while still maintaining systems that operators trust and understand.
“With so many systems in place and heterogeneous OEMs putting different standards in the market, the main thing OATI prides itself on is our integration capabilities. We bring a lot of systems together onto a single pane of glass, so operators can make decisions quickly and effectively,” he added.
As the energy transition continues to accelerate, utilities are at a pivotal moment. The industry’s future relies on its ability to embrace prosumers, introduce new and diverse technologies, and provide tools that are both advanced and user-friendly. For Singh and OATI, the focus is still clear: helping utilities meet the challenge of a quickly evolving energy landscape.
“The customer journey needs to be seamless, innovative, and impactful—all while maintaining the reliability and trust utilities have built over decades,” Singh said.
The once static utility-customer relationship is now a dynamic one, and as Singh’s reflections at the OATI Energy Conference show, this partnership will shape tomorrow’s energy systems.powerplant
Jan 22, 2025
Power Grid International
Project Polo: The Plan To Build A 27-State Virtual Power PlantThe new guy starts on Monday, so the U.S. Department of Energy (DOE) Loan Programs Office (LPO) has been burning the candle at both ends lately, especially this week, rushing to allocate unspent Inflation Reduction Act (IRA) funding on promising clean energy and grid infrastructure projects.
How does a 27-state virtual power plant (VPP) sound?
Sunwealth Holdco 18 LLC (Sunwealth) has closed on a $289.7 million loan guarantee with the LPO to finance Project Polo, a scheme to deploy up to 1,000 solar photovoltaic (PV) and battery energy storage systems (BESS) across 27 states. SYSO Technologies of Boston, Massachusetts, will provide its software platform to help all of those distributed energy resources (DERs) communicate, creating a massive VPP.
Sunwealth, a commercial solar financier, developer, and owner-operator based in Cambridge, Massachusetts, has a ten-year operating history serving commercial solar markets without defaulting (probably a plus for the people considering loaning them money).
Project Polo will include behind-the-meter DERs and community solar projects, primarily targeting commercial and industrial properties. Project sites include building rooftops, parking lots, multi-family properties, and underutilized land parcels across the United States.
Sunwealth estimates an aggregate capacity of 168 MW of PV and 16.8 MW (33.6 MWh) of BESS, which would lead to the avoidance of up to 4.07 million metric tons of carbon over the project’s lifetime.
The Sunwealth VPP offers advanced management of PV and BESS, enhanced forecasting of PV production and coincident peaks, and aggregation and dispatch of DERs. The software manages the PV and BESS as a VPP to support grid stability and resilience while generating additional revenue by enabling the participation of DERs in VPP programs and wholesale markets.
Project Polo is expected to create about 3,700 jobs, including approximately 1,900 solar and storage installation gigs and over 1,700 operations and maintenance jobs.
Deploying clean energy resources in disadvantaged communities without access to traditional financing is a key component of Sunwealth’s mission and strategy, which aligns with the DOE’s energy equity goals. Sunwealth has historically deployed approximately 40% of its systems to benefit disadvantaged communities and aims to install between 20% and 50% of PV plus BESS in disadvantaged communities for this project.
Sunwealth’s loan guarantee is offered through LPO’s Title 17 Clean Energy Financing Program, which includes financing opportunities for innovative energy and supply chain projects and projects that reinvest in existing energy infrastructure.
The company submitted its application to LPO in October 2021. It got the green light not a moment too soon, as it appears likely President Trump will pump the brakes on DOE’s rampant clean tech spending. Across all LPO programs, the DOE has attracted 182 applications for projects across the country totaling more than $278.9 billion in requested loans and loan guarantees as of December 2024. That figure has been bolstered significantly over the last few weeks, as the LPO has pumped out promises of cash to utilities and clean energy companies before Trump takes office on January 20.
The U.S. boasts roughly 30 GW of VPP capacity right now. A fresh DOE report, Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update, provides a revamped roadmap for the public and private sector to accelerate the commercialization of VPP technologies.
The DOE contends that in order to reach a target deployment of 80-160 GW by 2030, we’ll need to pick up the pace.
Achieving “liftoff” will require progress on five imperatives:
Since the original VPP Liftoff report was released in September 2023, DOE said the pressures on the U.S. grid have intensified. Peak demand is expected to increase from approximately 800 GW in 2024 to approximately 900 GW in 2030 due to growth in energy-intensive data centers, domestic manufacturing, and the electrification of transport and heating.
Learn more about the DOE’s guidance to achieve VPP “liftoff” here.
Originally published in Renewable Energy World.powerplant
Jan 17, 2025
Power Grid International
The Fcc Wants To Expand The 900 Mhz Broadband SegmentThe Federal Communications Commission (FCC) has adopted a Notice of Proposed Rulemaking (NPRM) to modify the 900 MHz rules, providing the flexibility to grow the 900 MHz broadband segment from 3 MHz by 3 MHz to 5 MHz by 5 MHz.
After the release of the NPRM, the FCC will seek comments and reply to them before any potential final report & order. This expansion is an option the FCC considered in its original rulemaking in 2020 modifying the 900 MHz rules when it approved the 3/3 MHz broadband segment, considering it premature at the time. Anterix, a broadband solutions company, argues that expansion of the 900 MHz band to permit 5/5 MHz broadband will support growing demand for wide-area, private, and secure wireless broadband networks for utilities, critical infrastructure, and business enterprise entities, among other benefits.
“We applaud the FCC for its leadership and commitment to improving the operations and security of our nation’s evolving electric grid through the deployment of private LTE enabled by 900 MHz broadband spectrum,” said Utility Broadband Alliance executive director Bobbi Harris. “Critical communications capabilities are playing a key role in the grid’s ongoing evolution to support our nation’s resilient energy future, and today’s action by the Commission is an incredible step toward enhancing those benefits.”
The adoption of the NPRM is the next step in a proceeding endorsed by more than thirty organizations, including key utilities.
“Access to expanded 5/5 MHz broadband networks will provide utilities, such as Xcel Energy, with additional capacity to support 900 MHz pLTE broadband deployment with enhanced broadband communications capabilities,” Xcel Energy said in a statement. “The ability to pursue a 5/5 MHz network would increase the options and opportunities for Xcel Energy to enhance cybersecurity and reliability for its operations and customers.”
The 900 MHz band is designated for narrowband land mobile radio communication used by land transportation, utility, manufacturing, and petrochemical companies.
The original order in 2020 made available six of the 900 MHz band’s ten megahertz for broadband services while retaining four megahertz to continue incumbent narrowband operations. The regulatory framework allowed 900 MHz licensees, like Anterix, to obtain broadband licenses and included operational and technical rules meant to minimize interference to narrowband operations.
The long-awaited, 2020 proposal aimed to modernize the 900 MHz spectrum band so utilities could deploy private, secure LTE networks across their infrastructure.
“Leading utilities including Ameren, Southern Linc, and NY Power Authority have long viewed private LTE as the future of utility network communications, as evidenced by their membership in the Utility Broadband Alliance (UBBA) and the number of experimental licenses out there,” Rob Schwartz, president of Anterix, the company that owns this spectrum, said at the time.powerplant
Jan 17, 2025