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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.
January 2026: Electric trucks, buses round-up Share on XJanuary announcements included several exciting deployments for heavy-duty and freight focused operations, including a large Class 8 deployment in Texas, several semi-trucks delivered in New York and an expanded partnership for intermodal shipping in California.
Largest known deployment of Class 8 battery-electric trucks set for Texas
A pilot procurement project led by the Center for Green Market Activation and Smart Freight Centre will deliver the largest known deployment of Class 8 zero-emission trucks in Texas to create an all-electric freight corridor between Houston and Dallas. The initiative aims to send a strong demand signal that encourages manufacturers to scale up production. The program will deploy 40 battery-electric heavy-duty trucks operated by Nevoya across Texas and the Southwest by late this year and early next year.
Upcoming delivery of Volvo VNR electric trucks to City Harvest marks major step in ‘Bronx is Breathing’ initiative
Volvo Trucks North America will deliver three zero-tailpipe-emission Volvo VNR Electric trucks to City Harvest in 2026 as part of the Bronx is Breathing project, a $10 million New York Clean Transportation funded initiative aimed at cutting noise and air pollution in South Bronx communities near a major freight corridor. The battery-electric trucks will enable fully zero-emission food rescue and delivery across all five New York City boroughs. Future charging will be developed around a freight-focused public hub by MN8 Energy featuring DC fast chargers and heavy-duty truck stalls in 2029.
RoadOne expands Tesla partnership with first of up to 10 Semis
RoadOne IntermodaLogistics announced the addition of a Tesla Semi to its fleet as part of an expanded partnership with Tesla, and plans to deploy up to 10 electric semis in Oakland, California. The truck has been in active service for several months and has exceeded performance expectations. The Tesla Semi is reported to offer up to 500 miles of range.
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 February. In the meantime, check out EDF’s Electric Fleet Deployment & Commitment List to track announcements as they happen in real time, and view all January announcements.
Check out last month’s announcements here.
The medium- and heavy-duty electric vehicle landscape has transformed dramatically over the past five years. In early 2020, electric trucks were a rarity on U.S. roads, and most fleets were only beginning to think about how electrification might fit into long-term transition plans. Today, the electric vehicle market looks very different: Rapid maturation has led to the deployment of over 38,000 medium- and heavy-duty electric trucks across 386 fleets, shifting from initial pilot projects to early-scale adoption.
In 2020, there were a total of 219 electric trucks on the road, according to EDF’s Electric Fleet Deployment & Commitment List, with announcements spread across 66 companies. During this time, fleets were starting to make public commitments to deploy electric trucks and largely focused on pilot projects or initial learning efforts. Several of these early commitments, like Amazon’s announced order of 100,000 Class 2b Rivian vans in 2019, signaled where the market was headed as technology improved and more options became available.
Electric truck deployments sustain momentum through a challenging 2025 Share on XBy 2021, that acceleration became evident. The market saw the first major increase in deployments, with 611 trucks hitting the road in a single year, bringing the total above 800. Growth accelerated further in 2022, as the cumulative total of electric trucks on the road reached 2,898. That year also marked a turning point in the scale of fleet commitments, with more fleets announcing larger orders of electric vehicles. Notably, the U.S. Postal Service committed to transitioning their delivery fleet to electric with 45,000 Next Generation Delivery Vehicles, and Walmart committed to over 10,000 electric vehicles across several manufacturers for last-mile delivery.
The passage of the Inflation Reduction Act in 2022 set the stage for rapid growth of the MHD electric vehicle market in 2023 and 2024. IRA investments paired with strong vehicle standards helped set clear direction for manufacturers, fleets, utilities and infrastructure providers to advance cleaner truck technologies — delivering meaningful air quality and public health benefits in communities. This jolt in funding and expanded market access, along with fulfillment of earlier orders as production time decreased, led to a record year of deployments in 2023, with 10,675 trucks deployed. Momentum continued in 2024, which surpassed the previous year’s record, with 15,431 deployments. In total, 26,106 MHD electric trucks were announced over two years, compared to 2,898 over the previous several years of tracking.
After consecutive years of exponential growth, the electric vehicle market entered 2025 facing heightened headwinds after the repeal of the Inflation Reduction Act, but major investments from previous years laid the foundation for continued progress. Despite the challenges, 2025 still saw continued investment in electric vehicle infrastructure, as fleets committed to or placed on order more than 134,000 MHD electric vehicles nationally since the passage of the Inflation Reduction Act.
Announcements of new vehicle deployments remained strong in 2025, with 9,139 deployments announced during the year. This represents a modest 14% decline from 2023, the second highest year on record, for a deficit of only 1,536 trucks. As the third-highest deployment year on record, 2025 proves that zero-emission vehicle solutions are still viable.
In addition to deployments, 2025 saw broadened participation across companies with 49 new fleets announcing deployments, and 20 fleets announcing new order commitments. In 2025, 61% of fleets announcing deployments were doing so for the first time. At the same time, nearly half of the fleets placing new orders already had an existing electric MHD order or deployment announced, signaling continued confidence among those early adopters.
While 2025 began with uncertainty, the year ended with a robust number of new MHD electric vehicles hitting the road. Looking ahead, 2026 will likely face continued headwinds from changes to incentives or economic and supply chain constraints. Even so, electric trucks remain viable solutions to reduce emissions and improve financial and operational efficiency. Because of this, fleets will remain well positioned to shape the next phase of the zero-emission transition and make zero-emission technologies standard, not the exception.
Fleets can continue to move the market forward by:
Since 2020, the transportation industry has made great strides in improving the health of our communities and reducing harmful pollutants from diesel trucks, but we must sustain momentum to achieve 100% zero-emission truck sales and net-zero emissions by 2040.
Fleets interested in starting or continuing their electrification journey can check out EDF’s Fleet Electrification Solution Center for resources, and EDF’s Electric Fleet Stories case studies series to see how other fleets are making alternative fuels work. Additionally, Electric Fleet Deployment & Commitment List tracking tool has up to date data on orders, deployments, and commitments. Stay tuned for new and exciting updates to the Deployment & Commitment List coming in 2026.
By Aashney Shah, EDF Legal Intern, Clean Energy Transition
“Electricity is the new price of eggs.” That line, from a recent New York Times article on rising electric bills and data center growth, captures the political moment with startling clarity. Consumers want solutions. While states have been exploring a wide range of actions to address affordability and equity, policymakers still face a core question: How can we ensure that the biggest benefits reach the communities that need them most?
As equity mandates rise, delivery is the real test
States have begun to codify such distributional mandates for energy. To name just a few, Illinois’ Climate and Equitable Jobs Act requires that “at least 40% of the benefits” of grid modernization and clean energy should go towards Equity Investment Eligible Communities;” New York’s Climate Leadership and Community Protection Act requires at least 35 percent, with a goal of 40 percent, of the overall benefits of investments related to clean energy and energy efficiency programs be directed to disadvantaged communities, and Washington’s Healthy Environment for All Act requires agencies to direct “40% of all grants and expenditures that create environmental benefits to vulnerable populations and overburdened communities.”
While many of these states are developing new electric grid plans, the numerical guidelines may be helpful. However, the task is complicated by the fact that many “benefits” are unquantifiable. The answer thus requires more than funding tallies or box-checking exercises. Instead, it requires modern, credible equity analysis grounded in community expertise and rigorous methods that measure real outcomes. Here’s how states can build grid plans that actually deliver:
1. Use a four-part equity framework to score benefits more accurately
Illinois’ 2024 refiled plans highlighted a critical flaw in traditional approaches: utilities relied on binary scoring – a simple yes/no – when evaluating qualitative benefits. Regulators required a more rigorous method, noting that a simple “yes/no” hides meaningful differences in benefit levels and fails to show exactly how investments meet the 40% benefit requirement for Equity Investment Eligible Communities (EIECs). A stronger approach, which contributed to a straw proposal that the Commission ultimately approved, evaluates investments across four established equity dimensions:
Scoring measures across these four dimensions creates accountability and clarity; something binary scoring simply cannot achieve.
2. Start with authentic, ongoing community engagement
Research consistently shows that utilities cannot achieve equitable outcomes without two-way, long-term engagement with communities. Effective engagement builds trust, improves social acceptance, and helps ensure solutions reflect real needs. A comprehensive review of 51 equity-focused energy projects found that community engagement efforts that are context-specific are more likely to lead to more equitable energy outcomes, which requires approaches that reflect the diverse perspectives of the communities impacted.
Utilities should identify the engagement process behind each proposed measure and show how it informs the project and its equity analysis. Simply treating spending as a proxy for community benefit may deepen mistrust. Meaningful engagement which shifts the focus to quantitative and qualitative impacts on the community are more likely to be accepted through strengthening trust, especially in communities who have long been excluded from decision-making.
Distributional Equity Analysis provides a practical model by embedding community input into equity metrics, program design, and investment prioritization. California’s Microgrid Incentive Program utilized this approach to generate equity “scores” through stakeholder workshops, enabling transparent evaluation of whether projects met legislative goals.
3. Apply quantitative tools that capture real community impacts
Various proven, practical tools have been developed that quantify equity impacts more accurately than simply cost totals and participation numbers:
Together, these tools allow regulators to pursue equity using empirical measurements, not theoretical projections, increasing the chances that communities experience noticeable improvements to their quality of life because of these efforts.
4. Use community solar as a model for quantifiable, equitable outcomes
Community solar offers one of the clearest examples of how programs can deliver measurable, equitable benefits when designed intentionally. Studies show that community solar participants earn significantly less, are more likely to rent, and are more likely to identify as people of color or Hispanic than rooftop solar adopters. In Illinois, policy accounted for 38% of the income gap reduction between non-participants and community solar subscribers, proving that program design – not just market forces – expands access.
Community solar also delivers meaningful bill savings, increases resilience and reliability, and can be more profitable under equity-enhancing policies. This reinforces a simple truth: deployment numbers alone cannot show whether benefits reach EIEC communities. Qualitative, equity-driven factors must be considered as well.
5. Measure energy burden outcomes – not just spending
Funding levels rarely reflect whether high-burden households actually see relief. That’s why researchers recommend tracking avoided burden (real dollar reductions in bills) and avoided need (burden reductions specifically for high-need customers). Metrics like operational and targeting effectiveness help utilities determine whether programs truly reduce energy insecurity. This shift from inputs to outcomes is essential for credible equity analysis and can help to address the root cause of inequities.
6. Pair distributed equity analysis with benefit-cost analysis
Benefit-Cost Analysis results alone only demonstrate the average impact on customers and do not disaggregate the costs and benefits to understand how they are distributed amongst various populations. Pairing DEAs, as described above, with BCAs allows regulators and utilities to provide a more complete picture of the program’s impacts.
By utilizing DEAs to develop context, identify priority populations, develop metrics, and apply such metrics to priority populations, pairing the results of DEAs provides more robust BCA results. This can be achieved by utilizing the BCA to understand the benefits and burdens of certain interventions of the average customer while utilizing the DEA to show how the benefits and burdens impact priority populations differently.
Building grid plans that deliver measurable equity
As states develop the next generation of grid plans, they have a powerful opportunity to move from check-the-box equity to real, measurable equity outcomes. By strengthening engagement, adopting multidimensional assessment frameworks, and using rigorous quantitative tools, utilities and regulators can ensure that grid investments deliver cleaner energy, lower bills, and greater resilience for the communities that need it most.
EDF will continue working with partners across states to refine these methods and support implementation. The moment demands solutions that work and equity analysis that proves it.
By Edwin LaMair, Senior Attorney, U.S. Legal & Regulatory, EDF and Ryan J. Call, Policy and Campaigns Specialist, Eco-Cycle
Landfills are a major – and growing – source of harmful pollution
When food scraps and yard waste end up in landfills, they rot and release dangerous air pollution. That pollution includes methane – a greenhouse gas more than 80 times more potent than carbon dioxide when measured over 20 years – as well as smog-forming compounds and toxic carcinogens like benzene and vinyl chloride. Landfills are now the third-largest source of methane emissions in America, making them a major driver of climate change and poor air quality.
Communities living near landfills bear the brunt of this pollution. Emissions often contain hazardous air pollutants that increase the risk of cancer and respiratory disease. Low-income communities and communities of color face these health threats most acutely, compounding existing environmental and public health inequities.
Proven technologies can quickly find and fix methane leaks
Fortunately, proven and affordable solutions already exist. Advanced technologies like drones and satellites can identify large, “super-emitter” methane leaks that traditional monitoring often misses. By integrating these innovations into regulatory programs, agencies can quickly pinpoint high-emitting sites and require corrective action.
Upstream solutions matter, too. Diverting organic materials from the landfill, such as composting food scraps and yard trimmings, and recycling paper, cardboard, and wood prevent organic waste from generating methane in the first place. But even if we diverted all organic waste today, the material already buried in landfills will continue to produce methane for decades. This reality makes strong landfill controls essential.
Colorado raises the bar on cutting landfill methane nationwide
In December 2025, the Colorado Air Quality Control Commission adopted leading standards to dramatically cut methane pollution from landfills. The regulations require stronger leak detection, improved methane capture and destruction, better landfill cover practices, and the phase-out of open flares.
Once fully implemented, these rules will deliver major climate and health benefits. In 2020 alone, Colorado landfills emitted 4.5 million metric tons of carbon dioxide (CO₂) equivalent – roughly the same climate impact as driving more than one million gas-powered U.S. cars for a year.
Broad support forged a practical, commonsense solution
A broad coalition helped shape these rules. Environmental Defense Fund, Eco-Cycle, Moms Clean Air Force, Full Circle Future, Western Leaders Network, GreenLatinos Colorado, Black Parents United Foundation, Clean Air Task Force, Earthjustice and several other environmental organizations all voiced collective support for stronger protections, emphasizing health, climate and environmental justice benefits. Large landfill operators, including Waste Management, along with municipal landfill owners, also participated in the rulemaking process. Together, the parties negotiated a practical, commonsense framework to cut pollution and meet shared goals. Key regulatory updates include:
Additionally, if remote sensing detects elevated methane emissions, landfill operators must investigate and begin corrective action within five days of notification and report results within fifteen days. All of these updates will reduce landfill emissions and lead to a cleaner, safer Colorado.
A national model other states can – and should – follow
Diverting organic waste remains the most effective way to prevent methane generation. EDF, Eco-Cycle and our partners will continue pushing for expanded composting and organics diversion programs to keep methane-producing materials out of landfills.
Colorado’s rules offer a powerful model for other states and federal policymakers. By adopting strong, scalable standards, the state is demonstrating it can curb landfill methane and protect public health efficiently. The benefits of state action far outweigh the costs. For example, Colorado estimates proposed landfill methane rules deliver at least $5 in benefits for every $1 in cost, with minimal impact on consumers. California reached a similar conclusion, finding benefits far outweigh costs.
With more states, such as New York, poised to act, transparent public processes and robust stakeholder engagement will be essential. EDF and Eco-Cycle will continue advocating for strong upstream solutions and robust landfill standards that deliver lasting climate, health and equity benefits.
California’s clean energy transition is no longer a question of whether the state electrifies, but how it does so – quickly, affordably and equitably. That reality makes one thing clear: grid planning matters more than ever.
Over the past year, state regulators have taken a series of important actions to modernize how the state’s large electric utilities forecast demand and plans to upgrade the grid. Taken together, these decisions move California away from reactive, worst-case planning and toward a smarter, more flexible approach that can support rapid electrification while protecting customers’ bills.
The work is not finished. But the direction is right – and now it is incumbent on the regulators and electric utilities to carry it through.
California is getting grid planning right – now we actually need to build it Share on XPlanning for electric demand that is actually coming
For years, the electric utilities have systematically understated future electricity demand and corresponding grid upgrade needs. That was not because electrification was not happening – it was because the antiquated rules only allowed utilities to plan for loads that were already firmly in hand. Everything else, including electrification projects still under development, was largely invisible to planners.
In December 2025, state regulators addressed this problem by allowing utilities to include pending electric demand in their forecasts – including customer electrification plans that are still being developed and credible, third-party electrification studies. The electric utilities can now plan for electric demand when supported by real-world data. This includes EV charging, building electrification, and other loads connecting to the distribution grid, rather than data centers and other large customers that connect to the higher-voltage transmission system.
In their action, regulators introduced a critical new concept: electrification hot spots. In areas in California where electrification of our buildings and transportation is clearly emerging, the electric utilities now have more discretion to proactively incorporate diverse data sources into their forecasts. That means fewer surprises, fewer last-minute upgrades, and better alignment between grid investments and customer needs. In effect, the regulators are directing the state’s electric utilities to plan for the future that is actually being built.
Moving beyond a single guess about the future
Just as important, California regulators are pushing the electric utilities to confront uncertainty head-on by directing them to adopt scenario-based load forecasting. Rather than anchoring grid plans to a single “best guess,” utilities must now evaluate at least three futures: low, mid and high load growth scenarios.
The electric utilities will pair this scenario planning with innovative decision-tree framework that guides how they should act under different outcomes – when to invest early, when to wait, and how to manage the uncertainty of their load forecasts. For example, California utilities plan for both high and low demand futures, so they can invest early when risks are high and hold back when demand may not actually happen.
This approach reflects a basic reality: overbuilding the grid is expensive but underbuilding it can be even more costly – missing opportunities to connect clean energy and locking in fossil dependence, emissions and reliability risks. Scenario planning, especially when combined with the new pending-loads framework, gives electric utilities a more disciplined way to strike that balance.
Integrating grid work to save money
Forecasting improvements alone are not enough. Execution matters just as much. Last month, the utilities filed a Commission-required proposal describing how they will better integrate capacity-driven grid upgrades with other distribution work. The concept is straightforward but powerful: when utilities are already replacing aging equipment or addressing safety needs, they should evaluate whether modestly upsizing that equipment today can avoid a second, more expensive project tomorrow.
For example, replacing a transformer at the end of its useful life without considering future load growth almost guarantees that ratepayers will pay twice – once now, and again when electrification demand materializes. This kind of integrated planning can reduce duplicative construction, lower costs and make better use of limited utility workforce resources. It also aligns closely with EDF-commissioned research from Black & Veatch showing that proactive grid planning is often the most cost-effective option.
While Environmental Defense Fund is not satisfied with the utilities’ initial proposal – and is actively engaging at the Commission to improve it – the CPUC’s underlying directive is well designed and worth supporting.
Electrification can lower bills if utilities plan for flexibility
In October 2025, Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric released draft studies examining how electrification will affect the electric grid – and how much electric demand flexibility can change the outcome. While this work will continue into 2026, the early results are striking.
PG&E’s analysis finds that while enabling electrification will require tens of billions of dollars in distribution investments through 2040, that same electrification could also save customers up to 25% by putting downward pressure on electric rates by improving system utilization. The takeaway is clear: electrification does not have to result in runaway costs to the customer’s electric bill.
When electric utilities actively plan for flexible demand – including managed EV charging, building electrification paired with demand response, and distributed energy resources – the grid can be used more efficiently, spreading the fixed costs of grid investments over more kilowatt-hours, and lowering costs for all ratepayers.
Turning planning into practice
None of these reforms will matter if they remain on paper. California’s regulators have laid out a thoughtful, forward-looking framework for electric demand forecasting and grid planning – one that supports electrification, improves affordability, and manages uncertainty instead of ignoring it. Now the hard(er) work begins.
The electric utilities must implement these tools rigorously and transparently.
Ensuring that California’s clean energy is affordable and reliable depends on getting this right. The good news is that the state has a planning framework in place to make this a reality. Now it’s time to start building.
Electric utilities have a well-established legal obligation to provide safe, reliable and reasonably priced electricity to customers in their service territories. That ‘duty to serve’ has long adapted to changing system conditions. Today, rapid electrification – driven by electric vehicles, building electrification, manufacturing and data center growth – is testing whether utilities are fully meeting that duty under modern circumstances.
Our recent Energy Law Journal article, Utilities’ Duty to Serve in an Era of End-Use Electrification, examines how traditional duty-to-serve principles apply to distribution systems experiencing renewed and uneven load growth. The article reaches a clear conclusion: many actions now framed as policy reforms are better understood as applications of utilities’ existing legal obligations to new factual realities.
Why the duty to serve matters now
For decades, electricity demand grew slowly, and utilities planned accordingly. That era has ended. Electrification of transportation, buildings and industry is driving significant new demand – often in large, concentrated increments that develop faster than traditional planning cycles.
These changes raise a core legal question: what does the duty to serve require when future demand is reasonably foreseeable, even if customers have not yet submitted formal service requests?
Anticipatory planning is part of the duty
Utilities have never planned the grid solely in response to customer requests. Load forecasting has always been a core utility function, and regulators have consistently expected utilities to anticipate demand to maintain system adequacy and reliability. What has changed is the pace and scale of electrification.
Under these conditions, the duty to serve already includes an obligation to plan for foreseeable changes in customers’ energy needs. Waiting to act until customers arrive can lead to unreasonable delays and inequitable outcomes. Where electrification trends are well documented, failure to plan for them may itself fall short of the duty to serve.
This is not a shift in the law. It is an application of settled legal principles to changing facts.
Adequacy and timeliness remain central
The duty to serve requires more than eventual service – it requires service that is adequate and timely. Lengthy delays in connecting EV chargers, heat pumps or electrified industrial facilities increasingly impede climate goals, economic development and equitable access to clean energy.
Utilities must ensure that forecasting translates into operational readiness. Regulators, in turn, should assess utility performance against these legal standards, ensuring utilities prepare their systems to meet foreseeable demand without compromising affordability or reliability for current customers.
Applying existing law to the energy transition
Interpreting the duty to serve in light of today’s electrification supports faster infrastructure deployment, more equitable access to clean energy, lower emissions and sustained economic growth. Several state commissions have already begun moving in this direction through proactive planning and interconnection reforms – efforts that reflect enforcement of existing obligations, not expansion of regulatory authority.
As electrification reshapes energy use nationwide, the duty to serve does not need to be reinvented. It needs to be applied. Anticipatory planning, timely investment and high-quality service are already core legal requirements – and they are essential to building a reliable, affordable and equitable electric grid for the future.
