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Louisiana is preparing for a new era of electricity demand. From data centers and advanced manufacturing to other large industrial facilities, companies are looking for reliable, affordable and more flexible ways to power new operations. That presents a significant opportunity for economic growth, but only if the state’s electricity system can keep pace without shifting costs onto existing customers or compromising reliability.
One proposal before the Louisiana Public Service Commission would allow qualifying large electricity users such as data centers to develop private use electrical networks (PUENs) to serve their facilities with privately developed generation while remaining connected to the electric grid.
Done well, PUENs could attract investment, accelerate deployment of clean energy and strengthen grid resilience. Without appropriate safeguards, however, private networks could leave Louisiana families and businesses paying for underutilized utility infrastructure while introducing new reliability challenges. As the Commission evaluates multiple proposals to meet growing electricity demand, it should consider them together so Louisiana can meet future energy needs efficiently, reliably and fairly. That’s why Environmental Defense Fund is urging the Commission to adopt a framework built around one simple principle: innovation should benefit Louisiana without harming existing utility customers.
The timing of this discussion is especially important. The Commission is simultaneously considering proposals that would dramatically reshape Louisiana’s electric system. Entergy is seeking approval for approximately 5,300 megawatts (MW) of new fossil fuel generation to serve a single customer, Meta, in addition to the 2,262 MW of new generation the Commission approved in 2025. Similarly, the Commission is also considering an Entergy proposal to construct two new 754-MW combined-cycle combustion turbine power plants.
Evaluating PUEN proposals alongside these broader planning decisions can help avoid duplicative investments and help ensure new infrastructure is built only where it delivers the greatest value. In our responses to the Commission’s questions, EDF recommends a framework that helps protect existing utility customers, assign costs fairly, encourage the deployment of clean energy and other low-emitting resources and ensure private networks strengthen, rather than undermine, the state’s electric system.
Protect existing customers first
As electricity demand grows, utilities make long-term investments in power generation, transmission and distribution based on projected customer needs. If a participating customer later leaves the traditional utility system after those investments have already been made, the remaining costs do not disappear. Instead, they can be shifted onto everyone else.
EDF recommends limiting PUENs, at least initially, to serving new electricity loads rather than allowing existing grid-connected customers to transition to private utility energy networks. Requiring utility commission review before utilities make major infrastructure investments helps ensure they remain necessary and cost-effective. That can reduce the risk of stranded assets and help protect households and small businesses from higher electricity bills.
The Commission should additionally establish objective eligibility criteria based on a project’s impacts on reliability, planning and cost allocation rather than limiting participation to specific industries or load sizes. Projects that deliver comparable public benefits, such as community solar, should also qualify if they meet the same standards. Applicants should simultaneously demonstrate that proposed projects will not create unreasonable cost shifting or stranded investments before they receive approval.
Make private network customers pay the costs their actions create
Private networks should not receive a free ride. Even facilities that generate much of their own electricity rely on the electric grid for backup service, emergency power and reliability support. Utilities must maintain generation and transmission capacity to serve those customers when their own systems are unavailable.
EDF recommends that participating customers pay the full cost of the infrastructure and grid services they require, including transmission, distribution, interconnection, standby and backup service. Those costs should be assigned to the customers creating them, not spread to other ratepayers. This follows a straightforward principle that regulators have long applied: customers should pay the costs they impose on the electric system.
Put private networks to work for Louisiana
Strong safeguards should not come at the expense of innovation. Properly designed private networks can give customers greater flexibility in how they meet their electricity needs while creating opportunities to integrate solar, battery storage and efficient combined heat and power systems. When designed to complement rather than replace the broader electric system, these projects can improve resilience, reduce strain on the grid during periods of high demand and support Louisiana’s growing economy.
One way well-designed private networks can provide these benefits is by enabling greater demand flexibility, allowing participating customers to rely more heavily on on-site resources or shift demand during periods of peak use. These capabilities will become increasingly valuable as Louisiana prepares for substantial growth in electricity demand in the coming years.
Plan ahead instead of reacting later
One of EDF’s most important recommendations is that private network proposals be evaluated early in utility planning. Rather than treating them as separate projects after utilities have already planned new infrastructure, the Commission should consider these proposals in the context of traditional utility solutions during resource planning and competitive procurement processes.
Early consideration allows utilities, regulators, and developers to compare alternative approaches, avoid unnecessary infrastructure investments and identify the most cost-effective solution for customers. Planning ahead also gives utilities better visibility into future electricity demand, making it easier to maintain reliable service while accommodating new investment.
Learn from other states while building Louisiana’s own path
Louisiana is not the first state to consider new approaches for serving large electricity users. Utah recently established a framework for privately developed generation serving qualifying large loads while maintaining regulatory oversight and protections for existing customers. Texas offers another example through ERCOT’s Private Use Networks, which allow privately managed electric networks to manage their own generation and load while remaining interconnected with the grid. When generation exceeds on-site demand, excess electricity may be offered into the ERCOT market, while the network may draw power from the grid when on-site generation is unavailable or insufficient.
These examples demonstrate that privately managed electric networks can coexist with the traditional electric system when supported by clear eligibility criteria, strong oversight and protections against cost shifting. Louisiana has the opportunity to build on these lessons while designing a framework tailored to its own laws, customers and economic priorities.
Getting the balance right
Louisiana can attract new investment while protecting the customers who already depend on the electric grid every day. By establishing clear eligibility rules, assigning costs fairly, preserving reliability and evaluating projects early in the planning process, the Commission can encourage innovation without asking existing customers to bear the risks. That balanced approach can help Louisiana meet growing electricity demand while supporting long-term economic and innovative growth.
Utility commissions are making some of the most consequential energy decisions in decades, from grid modernization to evaluating proposals for new data centers. They decide how to meet rapidly growing electricity demand, whether to approve new transmission lines, how to connect new manufacturing facilities and other large electricity users to the grid and, ultimately, how much customers pay for electricity. These decisions shape household energy bills, grid reliability, economic development and the pace of America’s energy transition for years to come.
As states invest billions of dollars in new energy infrastructure, the quality of those decisions matters more than ever.
Today, Environmental Defense Fund and Gridworks released Powering Participation: How Intervenor Compensation Can Strengthen Utility Commission Decision-Making, a new report examining one practical way states can strengthen the information utility commissions rely on to make informed, durable decisions.
Drawing on original research, interviews and surveys with more than 64 regulators and advocates, plus case studies from across the country, the report finds that well-designed intervenor compensation programs help commissions hear independent technical expertise, local knowledge and consumer perspectives they might otherwise miss. Together, those perspectives help commissioners test assumptions, identify risks, evaluate alternatives and make more informed decisions.
Better participation often leads to better decisions
Most utility commission proceedings resemble courtroom cases. Utilities typically arrive with teams of attorneys, economists and technical experts. Community organizations, consumer advocates, Tribes and local governments also have valuable expertise to contribute, but many lack the financial resources to hire attorneys, retain expert witnesses or conduct independent technical analysis.
Intervenor compensation programs help address this imbalance by covering reasonable participation costs for eligible organizations. The goal is to ensure commissioners hear the broad range of expertise and lived experience needed to make more informed decisions that the commission might otherwise not consider in their decision-making.
Our research found that effective programs help bring independent analysis and local knowledge into complex proceedings. In many cases, that additional expertise has helped commissions identify cost savings, strengthen consumer protections, improve utility planning and surface lower-cost or less risky alternatives.
Lessons from across the country
The report examines 13 active intervenor compensation programs and highlights six state case studies that illustrate different approaches and lessons learned. Michigan’s longstanding program has supported independent technical analysis that has strengthened utility rate proceedings and improved outcomes for customers. Massachusetts recently launched a grant-based program designed to reduce financial barriers before they prevent meaningful participation. Washington has paired funding with collaborative agreements that prioritize participation from organizations representing vulnerable communities.
Closer to home, EDF’s Community Voices in Energy effort demonstrates why local expertise matters. Community leaders have served as witnesses in utility proceedings, sharing firsthand testimony about energy affordability, utility disconnections and the challenges families face paying their bills. Their experience helps commissioners understand how regulatory decisions affect the people and communities they serve, adding valuable context alongside engineering, legal and economic analysis.
Each state has taken a different approach, but they share a common objective: ensuring utility commissions hear the strongest possible mix of technical expertise, independent analysis and community perspectives before making decisions with long-term consequences.
One of the report’s clearest findings
The research also found that funding alone is not enough. Many utility commission proceedings remain highly technical and difficult for new participants to navigate. Outreach, technical assistance and clear procedural guidance can help entities participate effectively and contribute meaningful analysis that strengthens decision-making.
The report also recognizes that intervenor compensation is only one tool for expanding public participation. Depending on the issue, workshops, informational meetings and other opportunities for dialogue may provide equally valuable insights and expertise into commissions’ decisions.
Looking ahead
Electricity demand continues to grow. States are planning major investments in transmission, grid modernization and new energy resources while working to keep electricity affordable and reliable.
As these decisions become more complex, utility commissions need access to the broadest possible range of expertise. Independent technical analysis, consumer perspectives and local knowledge all help commissioners better understand tradeoffs, test assumptions and make decisions that stand the test of time.
As more states consider creating or expanding intervenor compensation programs, they do not need to start from scratch. This report draws on experiences from across the country to identify practical approaches that can strengthen participation, improve decision-making and better serve customers and communities.
Read the full report to explore the research, state case studies and recommendations.
By Dynisha Benson, Legal Intern, and Tonya Calhoun, Senior Director, Community Engagement
The United States already hosts more than 3,000 operational data centers, and the AI boom is fueling one of the largest waves of industrial development in decades. As demand for computing power surges, data center construction is accelerating across the country. That rapid growth is putting increasing pressure on electricity grids and water supplies, especially in drought-prone regions.
Addressing these challenges will require large-scale investments and reforms to make our energy and water systems more efficient and resilient. But communities are already feeling the impacts today and are looking for solutions.
For too many communities, the first time they’re brought into the development process is when a data center breaks ground. Sites have been selected, permits approved, contractors hired and construction plans finalized, all without appropriate opportunity for community input. With many local governments feeling the pressure to accept developer conditions or risk losing out on the potential economic value of a new data center, residents often feel like they’re reacting instead of leading.
While many of the rules shaping the costs, energy, pollution and water impacts from data centers are made at the state level, residents and local leaders deserve a seat at the table and input on infrastructure that will affect them. Responsible data center development centers community priorities and emphasizes transparency, long-term planning and agreements that secure tangible benefits for families and businesses in areas that host these projects.
Developers are moving quickly to take advantage of the massive amounts of capital being invested into data centers, and that means state and local governments seeking tax revenue are increasingly fast-tracking development by shortening or bypassing traditional public participation requirements or granting these projects critical infrastructure status. Some developers rely on non-disclosure agreements with landowners, utilities and local governments during early-stage site selection. These agreements can shield critical details from public view, including project timelines, infrastructure demands, environmental impacts and even the identity of the company behind the project.
When approached by developers, local leaders have an obligation to keep their constituents informed about these projects. That can include hosting town halls and listening sessions to hear community concerns, collect questions, and offer clarity on development proposals. Local leaders can even invite developers themselves to participate in these meetings and directly respond to residents’ perspectives. Spaces like these not only build trust but also equip decision makers with information that can regulate further development.
Some states and communities are beginning to push back as concerns grow over the pace and transparency of data center development. Public opinion is increasingly skeptical of large data center projects, particularly when residents believe decisions are being made without meaningful local input or clear information about potential impacts on electricity costs, water resources, land use and quality of life.
In New Jersey, lawmakers are considering multiple proposals aimed at increasing transparency, limiting secret development agreements, strengthening public oversight and ensuring utility customers are not left paying for infrastructure upgrades tied data center growth. Under New Jersey’s Municipal Land Use Law, communities have the right to review information such as site plans, intended land use, traffic impacts, noise, environmental effects and infrastructure demands before decisions move forward.
Data center developments typically require multiple approvals, including zoning decisions, utility interconnection agreements, and air and water permits. Local leaders should determine what authority they have over zoning and permitting and which decisions are made at the state and federal level.
Communities can partner with land use, energy or environmental experts early in these approval processes to shape their outcomes. Strong technical comments focused on water use, grid impacts, emissions, cumulative regional impacts and ratepayer costs can carry particular weight with regulators. Environmental attorneys, legal clinics, and technical assistance organizations can help residents navigate the process and advocate for greater transparency.
For processes outside of local control, there are typically public comment periods or advocacy opportunities where local leaders and communities can make their voices heard.
In Pennsylvania, cities, towns and municipal associations, along with environmental groups like EDF, ratepayer advocates and others, all actively weighed in on Public Utility Commission rules regarding how data centers should cover their grid costs.
Early engagement in data center development can secure meaningful concessions in the form of community benefit agreements, including enforceable water-use limits, renewable energy commitments, commitments to hire locally and stronger noise protections. In cases where communities aren’t brought into the process until later, local leaders can and should still create avenues for input and oversight. Mayors and city councils can establish an advisory board to collect resident feedback on how tax revenues from data centers are spent and inform their top spending priorities.
The path toward a mutually beneficial outcome starts long before construction begins. Communities deserve transparency before deals are signed, opportunities to organize before hearings are scheduled and meaningful input before permits are approved. As debates over data centers intensify in statehouses and communities across the country, early and earnest public engagement will play an increasingly important role in determining how and where these facilities are built.
Utah and New Mexico have provided other oil and gas-producing states with a road map for addressing the long-standing and growing problem of orphaned wells.
By updating outdated well bonding requirements, both states are requiring oil and gas companies to set aside enough money to plug wells, rather than leaving taxpayers with the bill.
Orphaned wells, which no longer produce oil or gas, and no longer have a responsible operator of record, can leak oil, gas and other toxic chemicals into our air and water. If a company walks away from its legal duty to maintain and plug the well, the taxpayers are often saddled with the costs.
Federal investments under the REGROW Act have provided critical funds to find and plug existing orphaned wells, but plugging the backlog alone will not solve the problem. States also need stronger financial assurance, inactive well management and well transfer rules to keep today’s aging wells from becoming tomorrow’s orphaned wells.
In the last few weeks, we and our partners helped secure major wins in New Mexico and Utah that modernize antiquated bonding rules and help stop the orphaned well pipeline.
Both states took a risk-based approach to financial assurance requirements, applying amounts closer to the full cost of well closure for financially weaker operators and low- and non-producing wells, with the details tailored for each state. Both states arrived at the same key conclusion: blanket bonds covering multiple wells is a privilege, and not a right, and should only be available to operators who pose minimal risk of orphaning their wells.
Later this summer, the Texas Railroad Commission (RRC) will begin rulemaking for SB 1150, a 2025 law designed to address the growing number of the state’s inactive wells.
In January, Texas surpassed its previous record of 11,000 orphaned wells and 115,000 inactive production wells, which the RRC estimates will cost more than $15 billion to plug. If these wells are allowed to become orphaned, Texas taxpayers could be stuck with the costs.
Under the new law, wells drilled more than 25 years ago cannot stay inactive for more than 15 years and must be plugged unless they receive an extension or an approved closure plan through 2040. The RRC is tasked with developing rules around this new law, including safeguards for transfers of inactive wells – stout ambition is warranted given the recent spike in this well population, the immediate precursor to orphaning.
Utah and New Mexico have shown that states can act before wells become orphaned. Texas now has an opportunity to build on those lessons by requiring adequate financial assurance, derisking well transfers and ensuring operators either return inactive wells to productive use or plug them.
Like many other parts of the country, Florida needs more transmission to deliver electricity where demand is greatest. A modern electric grid depends on it.
Because new grid infrastructure requires major capital investment, the best practice is to optimize planning so selected projects can meet multiple system needs while minimizing costs for customers over the long term. This proceeding illustrates the risks of evaluating transmission projects in isolation rather than considering whether broader regional planning could identify more cost-effective solutions.
As electricity demand grows and extreme weather intensifies, utilities must invest in grid infrastructure that maintains reliability, strengthens resilience and delivers the lowest-cost electricity to customers. Those investments should meet a straightforward standard: before customers pay hundreds of millions (or even billions) of dollars for new infrastructure, utilities must demonstrate that a project is necessary, supported by evidence showing it is the most cost-effective solution available.
But in Florida, nearly all transmission infrastructure is built based on isolated, local reliability assessments that rarely consider the economic or resilience needs of the broader power system. Despite federal requirements, Florida Power & Light and the state’s grid planning organization have consistently failed to produce studies that rigorously assess the grid from a regional perspective.
Nor have they agreed to build, or even consider, a regional transmission project that benefits multiple utilities and their customers under a single investment. Such an approach would route power flow more efficiently, create a more resilient network with alternate pathways for electricity to reach consumers during stress events, and drastically reduce overall system costs.
Instead, Florida families and businesses are forced to foot the bill for massive infrastructure projects that often ignore cheaper, more effective alternatives. Florida’s investor-owned utilities have zero incentive to pursue lower-cost options or share project costs. Because of how they are regulated, their financial incentive points in the opposite direction: The more infrastructure they build and own, the higher their guaranteed profits – which customers pay on their bills. The rate of profit Florida’s utilities are allowed to earn is also rising, and now among the highest in the country. Meanwhile, customers face increasingly unaffordable electric bills, with the average household bill up 20% since 2021.
State utility commissions exist to restrain this dynamic: The larger the price tag, the more rigorous their scrutiny must be. This is critical to their mission of ensuring reliable service at fair and reasonable rates for customers. In this case, however, the Florida Public Service Commission failed to apply that level of scrutiny before approving FPL’s $782 million Andytown-Oasis transmission project. That is why EDF is asking the Florida Supreme Court to review the Commission’s decision.
A closer look at the evidence
In March, FPL petitioned the Commission for a “determination of need” to construct the Andytown-Oasis project, one of the most expensive local transmission projects ever proposed in Florida. If it moves forward, FPL’s captive customers will bear the full cost. Recognizing the staggering financial impact, EDF intervened to ensure the proposal received the rigorous public scrutiny it demands.
As with most of its major infrastructure builds, FPL based its proposal on a highly localized reliability assessment, concluding that four new high-voltage transmission lines, several upgraded substations, and a new substation were necessary to serve customers in Miami-Dade County.
EDF’s experts identified significant flaws in FPL’s analysis, raising questions as to whether an assessment designed around a narrow set of reliability scenarios could justify a project of this size. By ignoring regional planning mandates and operational alternatives, FPL failed to evaluate solutions that could address multiple system needs simultaneously and deliver far greater long-term value for customers.
Rather than addressing these issues, FPL sought to exclude our expert testimony through a series of unsuccessful motions. We successfully opposed those efforts, ensuring the Commission had the benefit of independent analysis identifying flaws in FPL’s proposal. EDF has worked in Florida for decades and represents thousands of members in the state, many of whom are FPL ratepayers with a direct stake in this decision.
Why regional planning matters
Planning transmission one project at a time, while ignoring current and likely future conditions across the broader system, misses opportunities to solve multiple grid challenges with a single, efficient investment. Across the country, modern planning approaches are driving a paradigm shift with the recognition that evaluating the grid regionally (not just within one utility service territory or pocket thereof) will identify projects that improve reliability, reduce congestion and lower costs across the entire electric system.
EDF asked the Commission to consider how broader regional planning could inform whether FPL’s proposal was truly the most prudent and cost-effective solution. Instead, the Commission concluded that regional planning was entirely irrelevant to its determination of need and even claimed it lacked jurisdiction to consider the federal regional planning processes Florida utilities are legally required to undergo, despite the Commission’s documented role as an indispensable party to regional planning decisions.
By putting blinders on, the Commission deprives itself of critical knowledge about the utilities it regulates and abdicates its statutory obligation to oversee prudent transmission planning. The consequences reach far beyond this single case: If regulators refuse to consider regional planning when evaluating massive capital projects, Florida ratepayers will keep missing out on better, cheaper energy solutions and continue overpaying for electricity.
The ultimate irony? FPL fully understands the immense value of regional transmission from its own experience decades ago. In the mid-1980s, FPL built a 628-mile transmission corridor connecting its grid with Georgia Power’s system to import cheaper out-of-state coal generation and displace its expensive oil units.
That initiative, worth more than $1 billion in today’s dollars, was a major interregional project that bridged Florida with the broader Southeastern grid while benefiting consumers. FPL proved decades ago that regional transmission can drive down system costs. The Commission must require it to do so again.
Advanced technologies can enhance ratepayer benefits
Proper review also requires looking beyond the utility’s preferred hardware solutions. Decades of innovation have produced advanced hardware and software, including Grid-Enhancing Technologies, that can address many transmission needs at lower cost and with far quicker deployment. Yet utilities rarely select them because cheaper solutions mean lower guaranteed returns.
FPL never evaluated whether these faster-to-deploy, lower-cost “non-wires” technologies could address its stated reliability needs, and the Commission gave it a free pass. FPL’s alternative project proposals merely changed the geographic route, not the underlying technology, of the Andytown-Oasis project. Yet regulators debated only these alternative paths for the same expensive wires.
Absent from the review was any meaningful evaluation of options like dynamic line rating, advanced power flow control, transmission-tied battery storage, or generation re-dispatch, all of which can relieve grid congestion and maximize existing capacity while minimizing power outage risk for a fraction of the cost of new lines. By failing to require utilities to study these technologies, the Commission lets monopolies default to the most capital-intensive option available.
Better scrutiny leads to better decisions
The Commission’s review moved at an extraordinary pace. For a nearly $800 million capital investment, EDF had only 13 days to digest FPL’s sprawling filings, analyze hundreds of pages of technical grid modeling, prepare comprehensive expert testimony, and file our motion to intervene.
Despite those constraints, our experts exposed glaring holes in FPL’s load forecasting assumptions that inappropriately attributed speculative data center growth to Miami-Dade County, challenged its isolated modeling that applied incorrect line ratings and highlighted its failure to evaluate regional or non-wires alternatives. That participation helped ensure these issues became part of the record the Florida Supreme Court will now review.
Strong regulatory decisions depend on comprehensive, rigorous records. Independent experts and consumer advocates help ensure regulators see the unvarnished facts rather than operating in an echo chamber. However, when the proceeding is so compressed and the Commission’s review process is forced to be so cursory, it inhibits other stakeholders from participating and usually limits the inputs to the utility’s own assertions, making that echo chamber virtually impossible for the Commission to avoid.
Why this appeal matters
This appeal is about much more than a single transmission project. As electricity demand surges nationwide, utilities are proposing ever larger investments even though federal rules require them to plan transmission across service territories, looking twenty years ahead and weighing reliability, economic, and public policy benefits. When utilities move forward with projects before adequately evaluating whether broader regional solutions could meet the same needs at lower cost, they can short-circuit tomorrow’s regional investments, saddle customers with higher bills and erode the incentive to build a truly interconnected grid.
The strongest transmission projects are the ones that withstand careful review because the evidence shows they are needed, cost-effective, and in the public interest. EDF’s appeal asks the Florida Supreme Court to apply that standard before Florida’s largest transmission project in recent history lands on customers’ bills.
Medium- and heavy-duty electric vehicles are hitting the road in 2026, and we’ve collected last month’s most exciting news. In 2025, EDF delivered monthly deployment updates on the biggest zero-emission transportation stories. By the end of 2025, it was clear that momentum was sustained throughout a challenging year. This year will undoubtably see more big announcements, and we’ll be here to showcase the biggest orders and deployments of zero-emission trucks happening around the country.
841 medium- or heavy-duty zero-emission vehicles were announced during the month of June. These announced spanned several vehicle types and use cases, including terminal tractors, Class 8 tractors and school buses. The range of announcements continues to demonstrate fleet confidence in zero-emission vehicles across the spectrum of use cases.
Electric terminal trucks have record month
Orange EV announced record order volume in June, including a single order for 600 trucks, the largest in the company’s history. Additionally, Port of Long Beach announced the deployment of 15 electric terminal trucks to aid in port operations, while APM Terminals Los Angeles announced a purchase order of 40 trucks, all manufactured by Orange EV. Both Port of Long Beach and APM Terminals Los Angeles had electric terminal trucks in operation prior to June announcements. Orange EV says they are seeing yard fleets place larger orders after initial trials, and that electric terminal trucks are past the early adoption stage due to superior total cost of ownership, uptime, reliability, fuel savings and service guarantees.
Tesla Semi gains momentum after entering mass production
Several fleets highlighted upcoming Tesla Semi deployments in June, including Hight Logistics, ArcBest and Bali Express. Hight Logistics currently operates several Volvo VNR and BYD electric tractors but shared the upcoming addition of 15 Tesla Semis to their fleet. ABF Freight, part of ArcBest, is following up a successful pilot program with a purchase order of two Tesla Semis for less-than-truckload (LTL) routes. Bali Express, currently operating six electric trucks, is adding 20 additional EVs to their fleet for drayage operations, which will include Tesla Semis.
Electric school buses continue to improve air quality
San Francisco, CA and South Bronx, NY area schools will see a combined deployment of 150 electric school buses over the next few years. South Bronx observes childhood asthma rates more than twice the national average, and the buses will contribute to increased air quality outcomes in both cities. Student mobility provider Zūm has announced the planned deployment of 105 buses for the San Francisco Unified School District, and GVC, a family-owned school bus company serving children with special needs in the Bronx, announced 45 new electric school buses to replace aging fossil fuel-powered buses. Each deployment will be accompanied by new charging stations to support the buses.
Now is a critical time for fleets to invest in medium- and heavy-duty electric trucks. These vehicles improve public health and help combat the climate crisis by reducing greenhouse gas emissions and air pollution. Unlike traditional diesel-powered trucks, electric trucks produce no tailpipe emissions, which significantly cuts down on health-harming pollution. Adoption represents a key step toward a more sustainable and resilient transportation industry.
Check back here next month to see a collection of the most exciting zero-emission vehicle announcements from July. In the meantime, check out EDF’s Electric Fleet Deployment & Commitment List to track announcements as they happen in real time, and view all June announcements.
Check out last month’s announcements here.
