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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.
On December 16th many Canadians were getting their holiday shopping done, and Canada’s Minister for Environment and Climate Change, Julie Dabrusin, was no exception. Luckily for all Canadians concerned about climate change and the competitiveness of our energy on world markets, she had a very special holiday present for us that was several years in the making: the finalization of new enhanced methane regulations for the oil and gas sector.
Methane is a powerful climate pollutant and the main chemical component of natural gas. Canada’s new rules will curtail these emissions by requiring energy producers to capture natural gas that would otherwise be wasted during the production process.
The new regulations are projected to reduce emissions by 72% by 2030 from 2012 levels, equivalent to the carbon pollution produced by over 70 million gas-powered cars in one year.
The enhanced standards are a massive step forward for Canadian climate policy and will deliver economic benefits for Canadians nationwide, but it is understandable that news of this major policy win may have gotten lost amidst the holiday season blur. Here is a crib sheet on these new requirements that highlights three big takeaways followed by a deeper dive into specific regulatory language.
In 2021, Canada set a national target of reducing methane emissions by 75% by 2030. However, the federal government recently signed a Memorandum of Understanding with Alberta that discusses a delayed 2035 target date.
Minister Dabrusin clarified how these targets, and the new regulations, can coexist in an interview on CBC’s Power and Politics. The Minister explained that the MOU doesn’t represent a delay because all provinces will need to achieve 72% by 2030, and that this outcome is compatible with Alberta achieving 75% by 2035.
Alberta is overwhelmingly the country’s largest emitter, responsible for 68% of Canada’s oil and gas methane emissions. The Minister’s assurance that all provinces will be subject to the regulations – and specifically the same 2030 target date – is encouraging, as the Pembina Institute estimates that granting a 5-year extension to Alberta would result in 1.9 million tonnes of additional methane in the atmosphere.
Besides the climate cost, special treatment for Alberta is even harder to justify while neighboring British Columbia has already developed and implemented its own regulations aimed at meeting the 2030 federal target.
An independent report looking at the methane mitigation industry – including 136 manufacturers and service providers that help Canadian energy producers reduce emissions – shows that Alberta is home to more than half of these companies’ offices. There’s good reason to expect the industry to grow quickly in the coming years: an EDF analysis estimates that 34,000 jobs are likely to be created by regulations that target 75% reductions. About half of these estimated jobs would be in Western Canada near the point of energy production, while the other half would be predominantly in Ontario’s and Quebec’s manufacturing hubs. Beyond job creation, regulations that prevent wasted gas also lead to more royalties for provinces. Giving special treatment to Alberta (like a 5-year delay) would mean delaying the onset of these benefits.
Prime Minister Mark Carney’s new Climate Competitiveness Strategy reorients climate policy around economic outcomes, noting that Canada can position itself to meet foreign markets’ demand for low-carbon energy. Ensuring all provinces meet the methane mitigation target by 2030 will help guarantee Canadian energy products can access large markets in Europe and Asia at a time when trade with the United States has become fraught.
At COP30 in Brazil, Canada signed onto a statement acknowledging that proven solutions exist to drastically cut oil and gas methane emissions by 75% by 2030 and that recognizes the importance of pursuing “efforts to near zero methane emissions… including clear policies to end routine venting and flaring by 2030.”
The new regulations, and the Minister’s assurance that Alberta will be subject to them, will help enable Canada to meet domestic and international climate targets while supporting economic development in Alberta and nationwide.
Environment and Climate Change Canada (ECCC) estimates that the average reduction cost for one tonne of carbon dioxide equivalent (CO2e) emissions through the regulation is approximately $48 CAD. A study by Dunsky Energy + Climate calculates these emissions at just $11 CAD per tonne. By comparison, a 2019 IEA analysis converted to present-day Canadian dollars shows that direct air capture of CO2 is estimated to cost up to $535, and capturing CO2 from industrial processes like cement and power generation are estimated to cost up to $155 and $187/tCO2e, respectively. The provisions in Canada’s new regulations are, in part, affordable because capturing methane means conserving valuable natural gas.
Some of the regulation’s key provisions include:
Leak Detection and Repair (LDAR): The regulation takes a risk-based approach to comprehensive leak inspections, meaning higher risk upstream oil and gas facilities must be inspected quarterly with either an infrared capable camera or an instrument capable of detecting hydrocarbons at a concentration of 500 parts per million by volume (PPMV). All other facilities must be inspected annually. Additionally, operators must conduct monthly instrument-based screening for large leaks provided an operator visits the site in that month. Lastly, operators must hire an independent auditor to conduct an annual inspection with the aim of identifying large leaks.
Venting: The regulation essentially prohibits venting from pneumatic controllers and limits venting from all but low-emitting/low-pressure storage tanks, dehydrators, and casinghead gas. The regulations include several exceptions for venting, including one for low producing oil facilities.
Destruction of gas: Flaring or combustion is prohibited unless the operator demonstrates that they are unable to use the gas to produce useful heat or energy. Hydrocarbon gas destruction equipment must include several features to ensure their efficient and proper function.
Continuous monitoring: As proposed, operators can opt out of the LDAR, venting, and flaring provisions if they install a gas monitoring system and if their facility emission intensity stays below specified thresholds. Operators that install emission monitors must conduct an annual audit for leaks.
Implementation timeframe: New sources of emissions must comply with all requirements by January 1, 2028. Existing sources must implement LDAR provisions by January 1, 2028, but have until January 1, 2030 to comply with all other requirements in the regulations.
By Kate Courtin & Magdalen Sullivan
Last month, New York State officials adopted the 2025 State Energy Plan, which will guide energy policy and investment decisions for the next 15 years. This is the state’s first energy plan since the passage of the Climate Leadership and Community Protection Act in 2019 – a landmark law that commits New York to cutting greenhouse gas emissions to net zero by 2050.
Because state agencies must align their decisions with the Energy Plan, it represents an important opportunity to drive full implementation of the CLCPA. In fact, state law explicitly requires the SEP to incorporate the Climate Action Council’s 2022 Scoping Plan – the state’s roadmap for achieving its climate targets through a managed, equitable energy transition.
Instead, the final plan falls short
The SEP ignores key Scoping Plan recommendations, under-prioritizes the most affordable clean energy solutions and doubles down on costly, polluting fossil infrastructure. It embraces an “all of the above” fallacy that fails to center clean energy – despite clear evidence that these solutions deliver long-term financial benefits while reducing health and environmental harms.
New York’s state energy plan falls short Share on XAs written, the SEP puts New York’s energy system on a trajectory that is incompatible with achieving net-zero emissions by 2050. The state’s own modeling shows that emissions between 2030 and 2040 exceed levels consistent with a net-zero pathway, regardless of whether emissions are measured using CLCPA or conventional United Nations Framework Convention on Climate Change accounting.
The state leaves billions on the table
New Yorks’s own modeling also makes the consequences of this failure unmistakable. A Net-Zero Pathway strategy could generate up to $35 billion in net benefits by 2040, from avoided health costs – like reductions in nonfatal heart attacks, asthma-related ER visits and lost workdays – and reduced climate damages. By contrast, the SEP’s chosen planning scenario delivers only $18 billion in net benefits – roughly half of what the state could achieve by committing fully to net zero.
The plan omits one of the state’s most powerful tools
Most glaringly, the SEP excludes a commitment to cap-and-invest regulations – known as the Clean Air Initiative – despite the Scoping Plan identifying such a program as a core strategy for meeting New York’s emissions limits. Cap-and-invest is projected to generate at least $3 billion every year to invest in programs that lower energy bills, create good jobs and deliver major health benefits, especially in communities burdened by air pollution. After years of policy development and stakeholder engagement, the program is ready for implementation. Its absence from the SEP underscores the plan’s failure to meet New York’s climate and affordability promises.
Clean energy saves New Yorkers money – if the state acts
The SEP itself acknowledges that efficiency and electrification deliver significant cost savings. State modeling shows that by 2031, households prioritizing high-efficiency electrification could save an average of $175 per month on combined energy and transportation costs – with savings reaching up to $335 per month for some households.
The SEP also recognizes that policies reducing upfront costs and adoption barriers are essential to realizing these savings and alleviating energy insecurity and burdens. That is exactly what cap-and-invest revenue is designed to do – scale investments in weatherization, public transit and efficient electric appliances and vehicles so that all New Yorkers can benefit.
Last year’s state budget took an important step by allocating $1 billion to clean energy and efficiency programs through the Sustainable Future Program. But one-time funding is not enough. To deliver lasting savings, healthier schools and homes and family-sustaining jobs, the state must sustain and scale these investments – including another $1 billion commitment in the FY2027 budget, followed by cap-and-invest.
Where the plan gets it right
The SEP does include several constructive elements that state agencies should embrace:
While these provisions matter, they do not compensate for the SEP’s broader failure to prioritize clean energy at the scale and speed that the climate crisis demands.
New York must close the gap
New Yorkers deserve clean air, affordable energy, healthy communities, and a livable future. The CLCPA – passed with broad statewide support – can deliver on all of this. But only if the state follows through.
Especially now, in the face of federal opposition to thoughtful policy, New York cannot afford to retreat. The State Energy Plan does not reflect the clean energy future New Yorkers have demanded. State agencies must act now to close the gap and put the state back on track to meet its climate commitments.
