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Climate Act Status – June 2026

New York’s Climate Leadership & Community Protection Act (Climate Act) is now driving every major energy and climate decision in the state. I’ve grown increasingly concerned that the transition plan built around this law is not affordable, is risky for reliability, and will not deliver the environmental benefits people assume. This post provides an overview of my concerns.

As a retired air‑pollution meteorologist who has spent a career worrying about both the air people breathe and whether the lights stay on, I am convinced that implementation of the Climate Act net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage.  I have followed the Climate Act since it was first proposed, submitted comments on the Climate Act implementation plan, and have written over 650 articles about New York’s net-zero transition.  The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.  I acknowledge the use of Perplexity AI to generate summaries and references included in this document. 

Climate Act Requirements

The Climate Act is often described in broad, aspirational terms, but its mandates are very specific. Public Service Law Section 66‑p requires the Public Service Commission, by June 30, 2021, to establish a program ensuring that at least 70% of statewide electric generation secured by jurisdictional load-serving entities in 2030 comes from “renewable energy systems” and that by 2040 the statewide electrical demand system is zero emissions. These statutory “targets” are the Climate Act’s headline electric-sector mandates translated into binding obligations on utilities and other load-serving entities, rather than being left as generalized policy goals.  On top of that, it sets a net‑zero statewide emissions target by mid‑century and directs a large share of climate and energy spending to “disadvantaged communities.”

To push enough wind, solar, and transmission projects through the pipeline to meet those dates, the state created new fast‑track siting regimes: first the Office of Renewable Energy Siting (ORES), and more recently the Renewable Action through Project Interconnection and Deployment (RAPID) Act, which folds big renewables and major transmission lines into a single accelerated process. In short, the law is not just a statement of long‑term goals; it has spawned a whole machinery of timelines, mandates, and permitting shortcuts to force the system in one direction. 

My over-riding concern is that the Climate Act set very aggressive goals without a realistic, step-by-step plan to get there.   We don’t have a plan; we have a wish list. The law sets big targets for cutting emissions, but there’s no practical roadmap that says who builds what, by when, and how we keep the lights on and bills affordable along the way.  This is declaring we’ll rebuild the whole electric system in 15 years without a construction schedule or budget.”

The law assumes everything will work out—technology, costs, and reliability—without proving it. No conditions have been defined.  There are no clear affordability limits, no defined reliability safeguards, and no trigger points where the state must slow down or change course if things start to go wrong.  I’m used to testing assumptions. Here, the assumptions are treated as facts.

The law ignores permitting reality. We make it harder and slower to permit both existing plants and new infrastructure, while at the same time assuming we can build massive amounts of renewables, storage, and transmission on a tight deadline. The timelines and the permitting system just don’t match. It can take many years to permit a single transmission line. The law acts as if we can permit and build dozens on a political timetable.

Affordability: what it looks like at the household level

From the beginning, the Climate Act’s architects asserted that the transition would be cost‑effective and could be done using technologies available a decade ago. In practice, when I look at the numbers through the lens of a typical upstate household, that claim is hard to square with the evidence.[

NYSERDA’s modeling and public messaging emphasize long‑term fuel and operating savings from electrification, but I believe they understate or obscure the full capital and retrofit costs that real people will face. A gas‑heated home in upstate New York is not starting from a blank slate; to electrify heat it may need a heat pump, electric panel upgrades, new wiring, backup systems, and often building shell improvements. When those costs are levelized over realistic lifetimes and added to electric bills that must also carry the cost of massive new generation, storage, and transmission, NYSERDA’s own calculations show annual costs rising by thousands of dollars compared to staying on gas.

That’s before we talk about vehicle electrification and the additional load that puts on both household budgets and local distribution systems. For low‑ and middle‑income families, especially in older housing stock, the up‑front burden is steep, and the promised payback periods are long and uncertain. The latest budget language envisions a cap‑and‑invest system that would raise revenue and then “share” proceeds with New Yorkers to offset bills, but that still means raising the underlying cost of energy to generate those funds in the first place. 

Previous energy transitions, for example, from coal town gas to natural gas, or from inefficient oil burners to modern gas boilers, succeeded because they saved consumers money and improved convenience. The Climate Act’s transition is different: it is enforced by law and regulation rather than emerging organically from better economics, and that is why I keep coming back to affordability as a core concern.

Reliability: weather‑dependent supply on a tight grid

My second major concern is reliability. The New York Independent System Operator (NYISO) prepares an annual report on “forces shaping the electric grid and wholesale electricity markets.”  NYISO’s Power Trends 2026 is a notable document because it acknowledges that Climate Act related initiatives such as electrification, retirement of conventional resources, and weather-dependent generation combined with large new energy-intensive loads are making the system more uncertain and more fragile. It also says reliability margins are shrinking and that winter conditions are becoming a defining challenge.

The Climate Act’s targets effectively assume that New York can completely revamp the electric system to run largely on wind, solar, and storage, with something called “Dispatchable Emissions‑Free Resources” (DEFRs) appearing down the road to back them up. In the Scoping Plan and State Energy Plan, those DEFRs are more of a placeholder than a commercially available option today.

As a meteorologist, I am very aware that wind and solar are controlled by the weather, not by grid operators. They are intermittent, they don’t work all the time; they are diffuse, they require large land areas and new transmission to deliver the same energy as a single conventional plant; and their output is correlated over large regions due to large‑scale weather systems. That means a cold, calm high‑pressure system can reduce wind output over the whole Northeast just when electric heating demand is highest, and clouds can reduce solar output across a broad swath of the state at the same time. The Scoping Plan and State Energy Plan acknowledge that DEFR is necessary for this situation but there is no proposal how to address this requirement.

Batteries are valuable for smoothing and short‑duration balancing, but they become very expensive very quickly if you try to size them to cover multi‑day or seasonal shortfalls. Studies that look at the cost of backing up long, widespread wind lulls strictly with storage point to staggering cost numbers and large amounts of capacity that would sit idle much of the time. Despite repeated warnings from the New York Independent System Operator (NYISO) about resource adequacy and the risks of retiring fossil capacity faster than firm replacements are available, I don’t see those concerns fully reflected in the state’s official transition roadmap.

My worry is that we are treating weather‑dependent megawatt‑hours as if they are interchangeable with firm capacity on peak and in worst‑case conditions and filling the gap with optimistic assumptions about future technologies. That may look fine in a model, but on a winter evening with a regional cold snap and limited imports, the real‑world consequences of getting it wrong would be very serious.

Environmental impact and local siting

People understandably assume that a climate law must be environmentally beneficial. My view, informed by decades of air‑quality work, is that the answer depends on how we define and measure “benefit,” and on the local impacts of the projects required to meet statewide targets.

On the accounting side, the statute originally used 20‑year global warming potentials (GWP20) and included out‑of‑state, upstream emissions from fossil fuel production in New York’s inventory. That approach gave very high weight to methane and made New York’s near‑term targets particularly difficult to meet compared to jurisdictions using 100‑year GWPs and more conventional boundaries. I have long argued that this approach magnified the appearance of urgency without changing global physics and raised the risk that New York would push expensive policies for relatively modest climate impact while encouraging emissions to “leak” to other regions.

The 2026 budget revisions change that accounting. They move to 100‑year GWPs, drop out‑of‑state upstream emissions, and exclude biogenic CO₂. Those moves align New York’s bookkeeping more closely with federal and international practice and immediately reduce reported statewide emissions—without any physical change in the atmosphere. The new law also softens the near‑term target, replacing the 40 percent‑below‑1990 mandate for 2030 with a 60 percent reduction by 2040, qualified by “to the maximum extent feasible and cost effective,” and pushes the deadline for DEC regulations out to the end of 2028.  The changes simply push the inevitable reckoning down the road.

At the same time, ORES and the RAPID Act change how projects are sited on the ground. These frameworks centralize permitting for large renewables and major transmission in Albany, set tight timelines, and include “deemed complete” and “deemed approved” provisions if agencies miss deadlines. Town associations, landowners, and even some developers have flagged that combination as a problem: local governments lose leverage, procedural timelines are very tight, and the opportunity to raise and adjudicate substantive issues is narrow.

From an environmental perspective, I worry that we are trading thorough site‑specific review and local consent for speed, especially in rural upstate communities being asked to host industrial‑scale projects for benefits that are mostly diffuse and global. That doesn’t mean every project is harmful or that renewables have no place, but it does mean we should be honest about the trade‑offs and the cumulative impacts of covering large areas of the landscape with energy infrastructure.

In my opinion, the biggest flaw with ORES and the RAPID Act is that they do not include specific conditions for developers.  Because there are no specific limitations for prime farmland protections, wildlife habitat, noise, or technology constraints, projects are being approved that will have long lasting adverse environmental impacts, health effects, and will require even more development.  For example, utility-scale solar development should use tilting axis panels that maximize solar collection and should not be sited in areas severely affected by lake-effect snow.

The 2026 “Reset”

One reason I am skeptical that these trade‑offs are being weighed objectively is the way the Climate Action Council and Energy Planning Board were put together. A clear majority of Climate Action Council members were appointed by the Governor and legislative leaders, and only a minority have deep energy‑sector experience, particularly in utility operations and reliability. The Energy Planning Board had one non-voting industry expert.  Given the obvious affordability problems, the 2026 budget revisions included a “blue-ribbon” commission on affordability that will have the same makeup.  I think the most probable outcome is a final report that acknowledges bills are too high, recommends more rebates and cost‑shifting to taxpayers, proposes tougher oversight of utilities, and treats NYISO reliability concerns as justification for even more spending on renewables, storage, and transmission—not as a warning sign about the Climate Act transition.

In my comments and blog posts, I’ve argued that this structure makes it unlikely that the Council would squarely confront feasibility and cost issues raised by NYISO and others. Instead, the Scoping Plan tends to assume that technologies and projects will appear when needed, and that equity goals can be layered on top of mitigation without exploding costs.  

The 2026 budget changes are, in a sense, an indirect admission that the original timelines and accounting structure were not realistic. They soften near‑term targets, adjust the emissions inventory in ways that make the numbers easier to hit, and give regulators several more years before binding rules must be in place. To me, that looks less like a fundamental reexamination of the transition plan and more like a political‑relief valve designed to avoid an imminent collision between statutory deadlines, litigation, and physical reality.

Discussion

I think we are at a crucial crossroads for New York energy policy.  Advocates have demanded that the future energy system reduce GHG emissions to zero citing major co-benefits from improved air quality.  Over my career I have seen enormous improvements in air quality, but there have not been corresponding health benefits that are consistent with the co-benefit claims in the Scoping Plan and State Energy Plan from the small incremental improvements from further reductions .

What I want from New York’s energy policy is something more pragmatic: a plan that starts from reliability and affordability constraints, acknowledges technology and permitting limits, and is transparent about both costs and benefits. That would mean putting independent technical experts, especially from NYISO and utility engineers—at the center of planning, not at the margins. It would mean evaluating wind, solar, storage, nuclear, and cleaner fossil technologies on a level playing field based on reliability contribution and life‑cycle cost, rather than committing in advance to a narrow renewable energy portfolio. And it would mean being honest with the public about what this transition will cost households, businesses, and communities, rather than leading with best‑case scenarios and hidden caveats.

Conclusion

The existing transition plan built around the Climate Act is not affordable, is risky for reliability, and will not deliver the environmental benefits people assume. I’m not saying, ‘do nothing.’ I’m saying: be honest with people. We need a realistic, engineering‑grade plan that respects reliability, affordability, and permitting realities, instead of pretending they’ll take care of themselves. We must concede that we are not ready to rely completely on zero-emission renewable resources today.  We must act now to develop natural gas infrastructure to ensure that we have a reliable electric system that can be used as a bridge to the future.  When full system costs and infrastructure life expectancy are considered I expect that nuclear power should be used as the backbone of the electric system.

New York Nuclear Reliability Backbone: Potential and Probability

Governor Kathy Hochul’s proposal for a 5-GW advanced-nuclear “Reliability Backbone” is a welcome acknowledgement of an issue that New York’s electric-sector planning has too often avoided: a system increasingly dependent upon weather-dependent wind and solar resources still requires firm, dispatchable generation when the wind is not blowing, the sun is not shining, demand is high, and transmission is constrained.  However, it is not clear whether New York is prepared to make the durable financial, regulatory, and political commitments that a real nuclear program requires.

I am convinced that implementation of the Climate Leadership & Community Protection Act (Climate Act) net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks coupled with cumulative environmental impacts of those resources. The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

Comment Submittal

The Independent Intervenors — Roger Caiazza, Richard Ellenbogen, Constantine Kontogiannis, and Francis Menton — have submitted comments in Case 26-E-0335 supporting important elements of Terra Praxis’s proposal for a Nuclear Reliability Backbone. However, our support is conditional. New York should not simply add nuclear generation to the enormous renewable-energy, battery-storage, hydrogen, backup-generation, transmission, and distribution buildout already contemplated under the Climate Leadership and Community Protection Act. If the State builds substantial quantities of new nuclear generation, it must reassess what other infrastructure can be avoided.

That is the critical point. Nuclear should be evaluated as an alternative to part of the renewable-heavy resource plan, not as one more costly mandate layered on top of it. The appropriate question is not whether New York can add 5 GW of nuclear to its existing plans. The appropriate question is whether 5 GW or more of dependable, dispatchable, zero-emission generation could reduce the need for wind, solar, battery storage, hydrogen-fueled generation, transmission lines, distribution upgrades, land conversion, and fossil-fuel backup.

The Terra Praxis comments cite a Coordinated Grid Planning Process scenario in which 5.5 GW of nuclear-like firm capacity enables New York to meet load with roughly 100 GW of installed capacity rather than approximately 130 GW in the State Scenario. The implications are obvious. A portfolio with sufficient firm generation may require substantially less weather-dependent generation and much less supporting infrastructure.

That comparison must be made transparently and using total system costs. It is not enough to compare the nominal levelized cost of energy from a wind turbine, a solar installation, a battery, a hydrogen turbine, and a nuclear plant. A reliable electric system must also pay for transmission, energy storage, backup capacity, interconnection upgrades, curtailment, fuel supply, land use, and the capacity necessary to survive low-wind and low-solar periods during winter peaks. The relevant metrics include accredited capacity, winter reliability performance, forced-outage risk, fuel security, construction and schedule risk, and the effect on customer bills.

The Independent Intervenors’ comments recommend that the Commission compare at least four alternative portfolios:

  • A renewable-intensive portfolio using the currently assumed buildout of wind, solar, storage, transmission, and dispatchable emissions-free resources.
  • A portfolio in which new nuclear provides a meaningful share of dispatchable emissions-free generation and thereby permits a reduction in renewables, storage, backup generation, and transmission.
  • A portfolio focused on maintaining or expanding existing zero-emission nuclear generation, with new nuclear added only when it is the least-cost, risk-adjusted alternative.
  • A portfolio that relies on other prospective dispatchable emissions-free resources only after those technologies demonstrate commercial maturity, sufficient duration, fuel security, accredited capacity, and competitive cost.

Consumer Protection is Essential

I support advanced nuclear because it is the only demonstrated large-scale, dispatchable, long-duration, zero-emission resource available today. Hydropower and storage are valuable, but New York cannot expand them enough to meet the entire need for firm capacity. Hydrogen, renewable natural gas, and long-duration storage may eventually contribute, but they have not yet demonstrated that they can be deployed at the scale, cost, and duration necessary to replace fossil generation throughout New York’s system.

However, supporting the concept of nuclear is not the same thing as accepting an open-ended commitment by electric customers. New York has a long history of expensive energy-policy mistakes, and large nuclear projects have particular cost and schedule risks. A nominally “fixed-price” engineering, procurement, and construction contract does not eliminate risk if the design is incomplete, the scope changes, the contractor lacks the financial capacity to absorb losses, or political pressure ultimately makes cancellation impossible.

For that reason, the Independent Intervenors argue that no project should receive customer-funded support unless the Commission first finds that it:

  • Has a demonstrated reliability need, including during winter peaks and periods of low wind and solar output.
  • Has a feasible site, cooling-water arrangement, deliverable transmission, and credible environmental and licensing pathway.
  • Uses commercially mature technology or places first-of-a-kind risk on developers and vendors rather than customers.
  • Has completed and independently reviewed engineering, constructability analysis, cost estimation, and schedule development.
  • Is competitive on an all-in, risk-adjusted basis with alternatives that provide equivalent reliability value.
  • Has enforceable cost, schedule, availability, and performance obligations.
  • Includes a hard project-cost cap, a customer-bill-impact cap, private-sector first-loss obligations, and clawback provisions for nonperformance.
  • Identifies the renewable, storage, transmission, hydrogen, or other investments that can be avoided because the nuclear project is built.

The comments also recommend that all revenues be counted. Customer support should decline if a project receives capacity-market revenues, energy-market revenues, ancillary-service revenues, federal tax credits, federal loan support, private offtake revenues, or other government assistance. Otherwise, customers could end up paying overlapping subsidies for the same facility.

The uncomfortable financing question

A reader asked me to review Rod Adams’s interview with New York State Energy Research & Development Authority (NYSERDA) President and CEO Doreen Harris.  It raises the most important practical question: is New York’s apparent nuclear enthusiasm real, or is it merely a political gesture designed to appeal to pro-nuclear Upstate constituencies while avoiding the difficult financial choices required to build reactors?

I do not believe the State’s interest is necessarily insincere. Harris described a serious set of planning activities: a 5-GW target for incremental advanced nuclear capacity, a direction to New York Power Authority (NYPA) to pursue at least 1 GW, a State master-plan process, site and technology evaluations, workforce and supply-chain efforts, and examination of financial and commercial mechanisms. She also explicitly acknowledged that nuclear projects will involve complex commercial arrangements among the State, the federal government, developers, vendors, communities, and private investors.

But planning, studies, memoranda of understanding, and policy-option papers are not the same thing as financial close, a construction notice to proceed, or commercial operation.

Harris was commendably candid that the State is exploring three broad roles: pre-development support such as early site work; possible State investment or ownership; and new forms of revenue support comparable in concept to the Zero Emission Credit program for existing nuclear facilities. She did not commit New York to any particular ownership model, cost-overrun guarantee, or customer-support mechanism.

That uncertainty is understandable at this early stage, but it is also the core problem. Nuclear plants require extraordinarily large, patient, and risk-tolerant capital commitments. A private developer cannot invest billions of dollars based only on the hope that a future administration, Commission, Legislature, or public campaign will continue to support the project through permitting, construction, cost escalation, and eventual operation.

My own experience in the deregulated electric-generating business makes me skeptical that private developers will undertake that risk in New York without unusually strong guarantees. I supported applications to replace old simple-cycle turbines at NRG Astoria. Those applications were completed, but the company ultimately chose to invest elsewhere. The projects did not proceed because the company could deploy its capital with less risk in other opportunities. After I left, the remaining permit application was denied because it was inconsistent with the Climate Act confirming their fears.

That experience involved conventional natural-gas repowering projects, not multibillion-dollar nuclear stations with long construction schedules, specialized supply chains, federal licensing, political risk, and the potential for major cost overruns. If a competitive generator developer would not commit capital to a conventional repowering project in New York, why should anyone expect a private investor to commit the much larger sums required for new nuclear generation without firm and durable protections against regulatory and political reversal?

New York’s credibility problem

Rod Adams opened his interview with an accurate description of New York’s mixed nuclear record. The State has four operating nuclear units with strong performance and high capacity factors. Yet it also has

the legacy of West Valley, Shoreham, and Indian Point.

The Shoreham experience is particularly relevant. The Long Island plant was completed after immense expense, but it never generated commercial electricity. According to Adams’s introduction, Shoreham had cost roughly $6 billion before it was sold and shut down at the direction of government. Whether one agrees with every decision involved in the Shoreham saga is not the point. The point is that investors remember that New York has demonstrated a willingness to change the rules after capital has been committed.

Indian Point presents a more recent version of the same credibility challenge. Two reactors with years remaining on their operating licenses were closed because of a political agreement, despite their role as large sources of dispatchable zero-emission electricity within the New York City contr. The State has preserved the upstate nuclear fleet through Zero Emission Credits, while simultaneously allowing Indian Point to close. That history creates an obvious concern for anyone asked to finance a new reactor: what assurance is there that New York’s support will persist when the project becomes controversial, expensive, or politically inconvenient?

The answer cannot simply be that today’s leaders support nuclear power. Nuclear projects take longer than election cycles, gubernatorial terms, PSC appointments, and changes in legislative priorities. Investors need credible, enforceable, durable commitments. Ratepayers, however, deserve protection against an open-ended obligation to pay for a project that is late, over budget, or abandoned.

Those two requirements are in tension.

My conclusion

I support the Nuclear Reliability Backbone as an acknowledgement that New York cannot operate a reliable zero-emission electric system using wind, solar, and short-duration batteries alone. If New York is serious about electrification, rising load, data centers, semiconductor manufacturing, winter reliability, and the retirement of aging fossil generation, it needs firm generation that can operate regardless of weather.

But I am not optimistic that New York will build out 5 GW of new nuclear generation easily.

The State’s energy-policy history, the structure of deregulated generation markets, the enormous capital requirements of nuclear construction, and the lingering political risk from Shoreham and Indian Point all make private investment difficult. A viable project likely will require a substantial State role: early site development, revenue certainty, possible NYPA participation or ownership, access to federal financing and tax credits, and a credible long-term contractual framework.

At the same time, that support cannot become a blank check. The State cannot reasonably promise developers enough protection to induce private investment while also guaranteeing that customers bear no risk. Something has to give. The likely outcome is that New York will have to choose openly among three imperfect options:

  • A primarily public or public-private project with significant taxpayer or ratepayer exposure.
  • A heavily subsidized private project with long-term revenue guarantees and carefully limited, but still real, customer risk.
  • Continued studies and policy announcements without a reactor actually reaching construction.

The Independent Intervenors’ comments take the proper position. New York should preserve the nuclear option and pursue the reliability benefits of dispatchable emissions-free generation. However, it should do so only after comparing nuclear honestly with the full system cost of the renewable-heavy alternative, identifying what redundant infrastructure nuclear can avoid, assigning construction and performance risk to the parties best able to manage it, and imposing firm limits on customer exposure.

The next step is not simply to procure nuclear. The next step is to decide whether New York is prepared to make the durable financial, regulatory, and political commitments that a real nuclear program requires. Until that question is answered, the Nuclear Reliability Backbone remains an important planning concept rather than a credible construction program.

Renewable-Energy Advocates Worried About Influencers and “Misinformation” Misinform Themselves

The September “Rise of Influencers and Misinformation” webinar was part of New Yorkers for Clean Power’s Renewable Energy Supporter Speaker Series. Barry Wygel, communications director for the Alliance for Clean Energy New York (ACE NY), framed the presentation as “glass half full, glass half empty”: renewable development is proceeding, but resistance to renewable-energy projects is becoming more coordinated, more visible, and more politically consequential. In this post I will address a clear double standard whereby the advocates condemn “misinformation” but make claims and cite references that are misinformation.  It is a long post because I document seven examples.

I am convinced that implementation of the Climate Leadership & Community Protection Act (Climate Act) net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks coupled with the cumulative environmental impacts of those resources. The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

Background

New Yorkers for Clean Power (NYCP) hosted a September 2026 webinar, The Rise of Influencers and Misinformation examining organized and social-media-driven opposition to renewable-energy development in New York. The seminar focuses on the communication environment surrounding utility-scale solar, wind, battery storage, transmission, and the State’s clean-energy transition. The recording is available here, the slide deck is available here, and a transcript that I prepared that includes the slides is available here. The transcript provides video links at the beginning of the discussion of each slide and for quotations that I consider particularly notable.

The principal subject of the webinar is Alexandra Fasulo, the Schuylerville-area farmer, online personality, and publisher of the House of Green Substack. Fasulo has built a large online following describing her concerns about the conversion of farmland and rural landscapes to utility-scale renewable-energy facilities. Her advocacy emerged from opposition to large solar development near her community, particularly the proposed Fort Edward Solar project in Washington County, NY. She now uses social-media videos, public-record requests, public testimony, Substack posts, and legal or quasi-legal participation in siting proceedings to challenge the Office of Renewable Energy Siting and Electric Transmission (ORES), developers, and state renewable-energy policy. House of Green presents itself as a platform focused on protecting American farmland, while Fasulo’s advocacy has broadened to encompass wildlife impacts, solar leases, rural property rights, local land-use authority, and the transparency of the state’s permitting process.

Fasulo’s central criticism is not limited to whether an individual solar project is appropriate. Rather, she argues that New York’s centralized permitting framework sacrifices meaningful local decision-making, transparent environmental review, and protection of farmland and wildlife habitat in the interest of rapidly meeting statewide climate and renewable-energy targets. In the Fort Edward proceeding, for example, she and allied advocates have objected to redacted threatened-and-endangered-species information, questioned the adequacy of proposed habitat mitigation, and argued that the siting process permits industrial development in environmentally sensitive rural areas. ORES responds that sensitive species-location information is legally confidential, that affected parties may obtain access through protective-order procedures, and that Article VIII requires a “net conservation benefit,” not complete avoidance of every project impact.  Unfortunately ORES never specified limits that defined acceptable development which I believe has left impacted communities few protection options.

ACENY and NYCP are worried about Fasulo because she has become an effective and influential communicator for a broader anti-renewable-development narrative. Her messaging can connect local anxieties about farmland loss, visual impacts, wildlife, property rights, and distrust of Albany with arguments that portray renewable-energy development and its permitting system as inherently corrupt, environmentally destructive, or imposed on unwilling communities. For both organizations, this is consequential because such claims can reduce local support for projects, intensify organized opposition, delay permitting and construction, and make achievement of the Climate Act’s renewable electricity targets more difficult for their members who think that it is necessary.

The NYCP concern is therefore as much about information and political mobilization as it is about one farmer or one project. Fasulo’s combination of personal credibility as a local farmer, a compelling social-media style, a rapidly expanding audience, and attention to real siting controversies gives her an ability to shape public perceptions beyond Washington County. Wygel repeatedly suggests that Fasulo uses misinformation in her arguments.  However, this argument is a double standard because his presentation includes misinformation.  The remainder of this post addresses specific instances of misinformation presented in the seminar and evaluates whether NYCP’s criticisms of Fasulo and her claims is supported by the available evidence.

Misinformation Examples

Video Link Claim – Savings from Solar Generation

On June 3rd NYS hourly solar generation set a record providing 29% of the power for New York. “That also means savings for the ratepayers. I think it was $200 million saved in in one day. You have to Google that NYSERDA quote that’s been out there.”

The NYSERDA reference is a July 2, 2026 news release, Eight Gigawatts of Distributed Solar Installed in New York. It says that on June 3, 2026, solar supplied “approximately 29 percent of statewide electricity demand during the noon hour,” which NYSERDA characterized as a new solar-generation record.  The release does not say that the June 3 solar-generation record produced $200 million in savings. It says that “Last summer,” solar generation “helped save New Yorkers an estimated $90 million” by reducing grid demand during peak-use periods.”  It also says “The FY 2027 state budget secured $200 million to expand NY-Sun.”  NYSERDA cited an estimated $90 million in peak-period savings from solar generation last summer and separately noted a $200 million FY 2027 appropriation for NY-Sun, but it did not attribute $200 million in savings to the June 3, 2026, solar record.

Video Link Permitting History and Renewable Climate Resiliency

And now we need to have thousands of new generation sources from rooftop solar to community solar to utility solar to wind to offshore wind. There was no permitting or way to do that. So it took this amount of time to build up a permitting regime in ores, to build up the way to go from a couple large generators to a distributed grid with generation all over the state, which is much, much better in the long run for resiliency for climate.

New York did not need the new ORES permitting regime because it lacked a permitting process. Article 10 already provided statewide siting for major electric generation, including renewable projects, with environmental review and meaningful public participation. ORES was a policy decision to speed and standardize renewable siting and to give the State greater ability to override local requirements—not the invention of permitting itself.

Distributed wind and solar are not automatically more “resilient for climate.” They can improve local outage resilience only when paired with sufficient storage, islanding capability, grid-forming controls, critical-load management, and hardened local infrastructure. Even then, the benefit is limited by storage duration, renewable output during the event, and the ability to operate safely as an islanded microgrid.

It is therefore spurious to characterize a weather-dependent electric system as inherently more resilient. Wind and solar output depends on the same weather conditions that can cause outages or stress the grid. Resilience must be evaluated by whether the system can reliably serve critical loads through credible, extended extreme-weather events—not by whether it includes distributed renewable resources.

Video Link Renewable Energy is Fastest Resource to Deploy

We’re actually net losing power sources to the grid. And this is something that’s, you know, been flagged as a problem and is being used by opponents of renewable energy to say that we’re not the way forward when we know that renewable energy is the quickest and fastest to deploy technologies if everything is allowed to go forward and there’s been a lot of hang-ups in there which we’ll get to later in the presentation.

Wind and solar facilities may be among the faster generation technologies to construct once projects are fully permitted, interconnected, financed, and supported by transmission. However, they are not dispatchable and therefore cannot, on their own, replace the capacity, energy security, ramping capability, and essential grid services supplied by retiring dispatchable generators. The New York Independent System Operator has argued that retirements should not occur until replacement resources providing equivalent reliability attributes are physically in service and demonstrated capable of meeting system needs.

Wygel claim treats nameplate renewable megawatts as interchangeable with dependable dispatchable megawatts. They are not. New York can add renewable energy, but reliability requires that it retain or replace dispatchable capability until long-duration, emissions-free, commercially proven alternatives are actually operating at the necessary scale and locations.

Video Link The Need for DEFRs

This is what a potential grid could look like if we meet our CLCPA goals in 2040.  It’s not impossible. It’s doable. Might not happen by 2040 and it 70% isn’t going to happen by 2030, but there’s no reason to think we’ll be that far off if we keep progress and keep moving forward and keep moving projects forward. Um, so people have modeled what a grid could look like and it is achievable to make the transition and meet the demand and needs that we have in the future.

This paragraph is misinformation by omission because the claim that it is doable presumes that the 10%  DEFRs will be available.  The chart shows a prospective New York energy strategy that relies heavily on weather-dependent wind and solar generation, and battery energy storage systems with implicit new transmission, imports, demand-side resources, and a future resource category called Dispatchable Emission-Free Resources, or “DEFRs.” The problem is that “DEFR” is a planning category, not a resource. New York State has not identified a specific technology that has been built, financed, permitted, interconnected, tested, and demonstrated at the scale New York needs to fulfill the resources required.

In my opinion the as yet-to-be-identified DEFR resource is an enormous risk to the wind, solar, and energy storage plans of NYCP and ACE-NY. If that scale of dependable capacity is necessary, State policymakers should answer basic questions now:

  • What technologies will provide the capacity?
  • Where will projects be located?
  • What will fuel, charge, or otherwise sustain them?
  • How long can they operate continuously?
  • Can they be permitted, financed, supplied, interconnected, and built in time?
  • Can their electricity be delivered to the locations where it is needed?
  • What will they cost customers?
  • How will they perform when weather-dependent generation is low, demand is high, and imports are constrained?

The presumption that this is “doable” should not presume that a future technology will be available simply because planners have assigned it a useful name. The fact is that without a viable DEFR the wind, solar, and energy storage plan is a false solution.

Solar Farms Comments

The following claims are introduced in this slide.

Video Link Leaseholder Investments

There was a survey done by Cornell of farmers who had signed solar leases in New York. And when they surveyed them, they found that three times farmers in New York were three times more likely to say they were going to use their solar money to invest in their farms and not stop it. So, farmers that are getting money from solar are not getting out of the farming game.  They’re using it to improve their farming.

I think this is misleading.  Solar-lease income may help some host landowners remain in farming or invest in their remaining operations. However, that individual financial benefit does not eliminate the loss of productive farmland, the harm to tenants and neighboring farmers who need leased acreage, the loss of food-production capacity, or the risk that construction and soil disturbance compromise future agricultural use. In my opinion, New York policy should therefore prioritize solar siting on marginal land, rooftops, parking areas, brownfields, and other lower-conflict locations—not treat lease payments as a justification for converting prime farmland.

Video Link Conversion Back to Farming

A national study found that 85% of farmland with solar, the owners of the land said they plan to either use it during the solar farm or eventually return it to agricultural use. Unlike permanent development, which is things like golf courses, where three times more prime farmland nationally is being used for golf courses than solar. And this um is about the same in New York. and takes a lot more water, too.

Solar equipment may be removable, but that does not mean a solar complex is cost-free, temporary in any meaningful agricultural sense, or assuredly reversible. The relevant loss is not merely the acreage under panels; it is the loss of farmable land for 25 to 40 years, plus the risks from grading, compaction, drainage disruption, access roads, collection lines, pile installation, and topsoil disturbance. New York’s detailed agricultural mitigation rules—including topsoil handling, drainage protection, monitoring, and decommissioning requirements—are an admission that restoration is not automatic.

The cited survey measures what landowners say they intend to do, not whether solar-project acreage will be returned with the same soils, drainage, productivity, and field utility it had beforehand. The reported observations at Excelsior Solar in Byron—where residents and landowners allege that topsoil was removed and crushed material brought in—underscore why the issue is construction performance and enforceable restoration, not simply the promise that panels can someday be taken away. Those allegations require independent verification, but they are exactly the sort of concern that environmental advocates should investigate rather than dismiss.

Video Link Comptroller Farmland Protection Audit

The comptrollers office did a really great analysis of land use in New York, and in their survey, they found that from 2017 to 2022, a bunch of farmland was lost in New York. 365,000 acres of farmland was lost, but only 1,700 acres of that was actually used  for solar. And that doesn’t even mean it was taken out of farm production. It just impacted that land. So the vast vast vast majority of land in New York of farmland being lost is from permanent development. It’s from housing. It’s from other uses. And these are the facts that we need to get out there because farming is not being killed by the solar industry.

The New York State Comptroller’s 2025 Farmland Protection Program audit, citing the USDA Census of Agriculture, reported that New York lost almost 365,000 acres of farmland and roughly 2,800 farms between 2017 and 2022. The audit identifies solar development and residential conversion as potential pressures on farmland, but it does not state that solar accounted for only 1,700 acres of the loss. 

My prime farmland solar scorecard is a simple accountability device: it asks whether a solar project respects the New York State Department of Ag and Markets 10% prime-farmland conversion goal. Its May 2025 results indicate that the guideline was often not met, leading me to conclude that New York’s solar-permitting system has not adequately protected productive farmland and that NYSERDA’s broader scorecard process needs enforceable standards, not simply voluntary siting guidance.  I was not able to figure how much prime farmland was lost between 2007 and 2022 consistent with the Comptroller report.  However, the total loss of prime farmland for projects in the permit queue in May 2025 was 12,476 acres.

Conclusion

This analysis of Wygel’s misinformation in his rebuttal of Fasulo’s arguments demonstrates his double standard.    There is every reason to be suspicious of a spokesperson from ACE-NY because their membership is only interested in developing as much renewable power as possible as soon as possible to maximize the profits of their members. 

What is a continuing mystery to me is why environmental advocates like NYCP do not demand environmental accountability from the developers.  The fatal flaw of ORES is that there are no clearly defined standards for acceptable development.  The authors of that law failed New Yorkers because they did not ask agency staff what was acceptable.  For example, the Department of Agriculture & Markets would have undoubtedly said make our recommendation that no more than 10% of the project area be prime farmland a requirement.  I am sure other agencies would have other recommendations for wildlife protections, health impacts, and development limits.  If the developers understood those limits coming in then they would not even try to permit development that did not meet the agency mandates.  Instead, we have a situation where ORES has permitted environmental impacts that are unacceptable and the developers are taking advantage of that situation.

In this environment it is no surprise that Fasulo’s messaging finds an audience.  That environmental advocacy organizations are not demanding the same protections she is advocating for is a conspicuous—and troubling—failure to hold renewable-energy developers to the environmental standards they claim to champion.

Guest Post: Ellenbogen – BESS is Currently a Science Project

Richard Ellenbogen sends detailed analyses to an extensive distribution list on an irregular basis and his recent description of  Battery Energy Storage Systems (BESS) as a science project was on my list to convert to a guest post.  On 9/18/26 there was another fire at the Moss Landing 300 Megawatt – 1200 Megawatt-Hour Vistra BESS facility touted as the world’s biggest battery storage project in August 2023 and that prompted me to publish this article.

Ellenbogen is the President [BIO] of Allied Converters and frequently comments on various issues associated with the New York Climate Leadership and Community Protection Act (Climate Act). I have published other articles by Ellenbogen including a description of his keynote address to the Business Council of New York 2023 Renewable Energy Conference Energy titled: “Energy on Demand as the Life Blood of Business and Entrepreneurship in the State -video here:  Why NY State Must Rethink Its Energy Plan and Ten Suggestions to Help Fix the Problems”. He is an engineer who truly cares about the environment but understands the practicality of clean energy solutions based on his experience as an early adopter of renewable technologies at both his home and business two decades ago.

Utility Scale Lithium-Based Energy Storage System Issues

In January 2026 I published an article describing his white-paper The Intrinsic Danger of Siting Utility Scale Lithium Based Energy Storage Systems In Densely Populated Areas.  He addressed  local public-safety and environmental-siting concerns. It was prepared in response to concerns about a proposed BESS in Hauppauge, NY and focuses particularly on the combination of a densely populated area, a nearby elementary school, streams, porous soils, and a shallow aquifer.  The Fire Department’s website notes that the Suffolk Water Authority is suing over alleged ground water contamination after the East Hampton lithium Battery Energy Storage Fire.  

Ellenbogen’s argument has three linked elements:

  • Thermal runaway and firefighting difficulty. He describes lithium-ion systems as vulnerable to overheating and thermal runaway, with fires that can be extremely hot, difficult to extinguish, and capable of releasing toxic gases. He argues that water may be necessary to cool adjacent equipment and prevent fire spread, while also creating contaminated runoff concerns.
  • Environmental consequences after a fire. The post uses the January 2025 Moss Landing fire as its principal case study. It cites research summarized in the post as finding deposition of nickel, manganese, and cobalt in surrounding coastal wetlands, with concern that tidal action and rainfall could mobilize contaminants more broadly through the ecosystem.
  • Long Island-specific vulnerability. Rather than treating all BESS sites as interchangeable, the paper stresses Long Island’s glacial geology, highly permeable soils, surface-water proximity, and dependence on shallow groundwater. Ellenbogen argues that these conditions would magnify the consequences of toxic-metal deposition or fire-related runoff.

His policy conclusion is a restrictive siting standard: utility-scale lithium-ion facilities should be confined to locations with few nearby people and without vulnerable surface-water or groundwater receptors. He frames this as a precautionary response to potentially severe but difficult-to-remediate contamination, rather than a blanket rejection of all BESS.

BESS is Currently a Science Project

The following is a lightly edited copy of his email with this subject line.

The battery technology may have advanced but it is still a science project that will not work on the downstate NY grid or the Con Ed System.  All high energy systems are prone to fires.  The problem with Lithium batteries is that there is no viable way to extinguish the fires.  The newer systems are better than the older ones, but they are not foolproof.  The Town of Islip and most of Suffolk County have now banned Lithium based BESS because a fire in 2023 contaminated their aquifer.  The Suffolk County Water Department is suing the battery system owners.  With all these BESS systems, there will eventually be a fire.  That’s not an “If” but a “When”.  I have worked with high energy electrical systems for 50 years and I have never seen one that was 100% fireproof.  My first job was overseeing the project that analyzed and tested the energy systems for AT&T/Bell Laboratories, which at the time was the world’s largest utility and operated 90% of the phones in the US.

I would never install a system that had no viable way to extinguish the conflagration and to do so is evidence of an unconscionable level of hubris.

There was a house fire on Pelhamdale Avenue in Pelham about a year ago.  Engine companies from Mt. Vernon, New Rochelle, and Pelham answered the fire.  Simultaneously, there was a fire alarm at the NY Athletic Club, and it took 45 minutes for first responders to arrive.  Fortunately, it was a false alarm, but what will happen if there are multiple fire crews battling a 24 hour BESS fire because that is a minimum of how long they take to extinguish?  Who will answer any other emergency events during that time?

I wrote a white paper for the Hauppauge Fire Department about a BESS System that a company wanted to install there that documents the dangers of installing these systems in populated areas.  A visit to the fire department web site will provide additional information, as well as information about the water contamination.  The paper is on the Public Service Commissions website.  Prior to the Suffolk County Water Department discovering the contamination at their wells, the paper documented the exact method of contamination.

Further, the same issues that caused the Yonkers Sewage Treatment plant to discharge 39 million gallons of raw sewage into the Hudson River during the early July heat wave will make battery storage on the Con Ed System nonfunctional when it is most needed.  BESS is needed but unfortunately, the lack of sufficient generation on the downstate system will cause a shutdown of the battery system inverters just as it shut down the Sewage Treatment Plant motor VFD’s.

The July 1 – 4 event had low voltages on the Con Ed system for over 48 hours so after the first discharge, the 8 hour batteries would be unable to recharge.  I own multiple grid connected inverters, the same technology that converts the DC in the batteries to AC for the utility system.  Everyone shut down during that prolonged outage.

I can provide detailed technical data and measurements that were collected at both my home and my factory.  The inverters that I own were providing frequency warnings throughout that four-day time period and shut down repeatedly.

NY State has to fix the downstate generation problems before any energy storage solution will add to utility system security/reliability and unfortunately, that is years away.  Without that, adding BESS Systems endangers the public and provides no added reliability benefit when it is needed most.

The post written by Roger Caiazza based upon data that I collected in New Rochelle and Pelham and shows the futility of using BESS Systems in the downstate region.

The US utility system has a frequency of 60 hertz (hz or cycles per second).  Under normal conditions, that frequency will vary between 59.95 hz to 60.05 hz.  During the July 1 – 4 period, the variation was ten times that.  When the frequency gets too far out of range, inverters shut down to protect themselves and the system.   When the system doesn’t have enough generation, the utility has difficulty in regulating it and that is what happened in early July, although no one seems to  want to say that.

For an example of what an inverter-based system does when there are frequency aberrations on the system, we need look no further than what happened on the Iberian Peninsula in April, 2025 when 9 Gigawatts of inverters turned off in a span of 5 minutes and the entirety of Spain and Portugal went dark.  They couldn’t even restart their own utility system and had to rely on French Nuclear reactors to provide the required grid inertia needed for a “Black” start.  The Wikipedia link documents the blackout.  For political reasons, no one wants to say exactly what happened because it will document their misallocation of utility resources.  However, I have seen the frequency graphs of the Iberian system just prior to the grid going dark and there was a major frequency issue.  That also occurred on the Con Ed system during the power problems in early July.  A paper that I wrote in 2008 for the NY State Public Service Commission after I installed my solar arrays predicted just such an issue.  It addressed local issues because in 2008, I never would have believed that someone would try to run the entire system with inverter based generation.  It’s a disaster waiting to happen.

On the downstate system that is over 90% powered by fossil fuel generation, storing that generation in batteries does not make the energy cleaner.  It actually increases the carbon footprint by 15% – 20% because of charging and discharging losses.  The renewable generation was cost prohibitive, even prior to the current administration’s policies implemented after January, 2025.  In 2023, the offshore wind was 2 – 3 times the cost of the current wholesale cost and CleanPath, the large renewable cable across the Catskills to NY City had cost issues in 2024 that led to its failure.  Federal policies have not helped that but with few exceptions,  the renewable generation  systems in NY State, other than rooftop solar, are not cost effective.  That is why NY State is years behind on its energy goals and systems that would have greatly reduced carbon footprints while providing sufficient generation have been blocked by state policy.  Expecting a large influx of renewable generation to solve the downstate generation issue has worse odds of success than buying a Powerball ticket at 380 million to 1 and expecting to win the jackpot.  They are cost prohibitive in NY State and as we have seen recently, utility costs are a huge issue.

The people proposing these systems don’t fully understand the technologies that they are working with and how they will interact with the utility system.  They are just trying to make money at great public expense, even though their lack of knowledge of their own systems probably makes them ignorant of that fact.

Sodium based battery systems would be less fire prone however they will still not work well without sufficient generation available and that is a minimum of seven years away for combined cycle gas turbines and fifteen years for nuclear generation.  Solar and Wind systems will have the same inverter issues that Spain and Portugal had.

State energy policy has left the system in a mess and BESS Band-Aids will not fix the problem.

They can install these systems which will raise utility costs, endanger the public, and simultaneously provide no benefits in terms of  utility system reliability.  If you approve them, the issues will become clear over time just as they did on Long island.

They certainly will not yield clean, affordable, or reliable generation on Con Ed’s system.

Caiazza Closing Remarks

Ellenbogen and I collaborated on an article describing the implications of the January 2025 Moss Landing battery plant fire.  We explained that the fire was a practical stress test of proposals to replace New York City peaking generation with large urban battery-storage projects—especially the proposed Ravenswood installation in Queens. The core conclusion was that a Moss Landing–scale BESS fire in the Ravenswood location could create an evacuation, emergency-response, transportation, hospital-access, and contamination problem vastly more consequential than the risks attributed to the peaking plants targeted for retirement.  The recent fire reinforces the potential for those impacts and supports Ellenbogen’s conclusions.

Climate Action Concerns Require More Than Attribution Headlines

Roger Pielke, Jr recently described “one of the most brazen — and successful — propaganda campaigns that sits out in plain sight”.  He was referring to “the concerted effort by climate advocates to create a belief that ‘climate change’ causes bad weather and disasters, and that we can prevent those bad things from happening with climate policies.”  I think he makes important points that are relevant to New York energy policy that is predicated upon the implicit belief that transitioning away from fossil fuels will reduce bad weather and disasters

I am convinced that implementation of the Climate Leadership & Community Protection Act (Climate Act) net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks coupled with cumulative environmental impacts of those resources. The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

The climate-policy debate has two questions

Public discussion of climate change often collapses two distinct questions into one:

  • Does human activity affect the climate system?
  • Does that fact justify any particular energy-transition policy, on any timetable, at any cost?

The answer to the first question need not determine the answer to the second.

The authors of the Climate Act assumed that human activity was the control knob for the climate system.  Carbon dioxide is a greenhouse gas. Human activities affect atmospheric composition and therefore the climate system.  However, climate is not controlled by one variable. The size, timing, location, and consequences of climate change depend on CO₂-related radiation effects, other forcings, including water vapor and clouds, ocean heat uptake and circulation, ocean-atmosphere oscillations, aerosols, volcanic effects, solar variability, ice and surface-albedo changes, and atmospheric circulation patterns and feedbacks between all those forcings.

Climate advocates have created a belief that ‘climate change’ causes bad weather and disasters.   They implicitly claim that attribution and quantification demonstrate that the anthropogenic component of a particular observed or projected impact exceeds natural variability sufficiently to justify a stated damage cost.  Pielke’s article explains why claims that extreme-weather impacts can be attributed confidently to anthropogenic climate change by World Weather Attribution (WWA) are based on assumptions and do not consider all the other factors that affect climate and weather. 

Those distinctions matter most in New York, where the Climate Act requires a sweeping transformation of the state’s electric system, buildings, transportation, industrial processes, and energy supply. The Act’s goals are aspirationally attractive: reduce emissions, improve public health, and create a sustainable energy future. But practical public policy must be judged by what it actually does—not by its stated intentions.

The pertinent question is whether New York can implement the Climate Act’s net-zero mandates without compromising electric-system reliability, making energy unaffordable, or imposing environmental and community impacts that have not been honestly acknowledged. My conclusion remains that the current transition plan is more likely to do harm than good if it depends primarily on wind, solar, and energy storage before dispatchable emissions-free resources capable of replacing fossil generation are commercially available and deployed at scale.

This is not an argument that the climate never changes, that humans have no influence on climate, or that emissions reductions are necessarily pointless. It is an argument for distinguishing evidence from assertion, weather from climate, and sound risk management from a policy program that assumes its preferred technologies will work regardless of demonstrated feasibility, cost, and reliability.

The weather-attribution problem

One reason the transition has acquired such political force is the widespread claim that each damaging heat wave, flood, wildfire, drought, hurricane, or heavy-rainfall event is evidence of a worsening climate emergency—and that rapid decarbonization will reduce such events.

That narrative is emotionally compelling, particularly after a disaster. It is also much easier to communicate than the actual scientific questions. Weather and climate are often confused.  Weather is the set of short-term atmospheric conditions at a particular place and time. Climate is the statistical description of weather over a long period. NOAA’s useful shorthand is that climate is what people expect, while weather is what they get. The distinction does not mean that climate change cannot affect the odds or characteristics of some categories of events. It means that an individual event does not, by itself, demonstrate its cause.

World Weather Attribution (WWA) has become a prominent source of rapid claims linking recent extreme weather to climate change. WWA describes its purpose as providing “real-time attribution analysis” intended to connect greenhouse-gas emissions to impactful extremes such as heat waves, floods, droughts, and storms. The resulting reports often generate headlines stating that climate change made an event more likely or more intense.

There are legitimate questions to ask about every such claim:

  • How was the event defined geographically and temporally?
  • What observations were used, and how long is the local record?
  • Can the selected models reproduce the relevant meteorology, the distribution of the particular extreme, and the regional climate setting?
  • What role did circulation patterns, sea-surface temperatures, soil moisture, ENSO, or other internal variability play?
  • What counterfactual assumptions were made?
  • What is the uncertainty interval around the reported change in probability or intensity?
  • How does a meteorological estimate become a conclusion about deaths, damages, or the value of a particular mitigation policy?

These are not rhetorical questions. They are the basic elements of a credible attribution analysis.

Pielke’s recent article is useful because it identifies a specific concern about the manner in which many extreme-event-attribution studies are framed and communicated. Pielke’s central point is that a common statistical approach begins by assuming that the principal shift in the distribution of an extreme-weather variable is due to global warming, then estimates how a present-day event would compare with a modeled or statistically reconstructed earlier climate. The criticism is not that carbon dioxide has no radiative effect. It is that a methodology can appear to establish causation when key causal premises are incorporated at the outset.

Pielke highlights methodological language from foundational attribution work that treats smoothed global mean surface temperature as the primary covariate for changes in extremes beyond year-to-year variability. He notes that four-year smoothing is used in some approaches to suppress ENSO-related fluctuations in the global temperature series. His concern is that this procedure does not independently adjudicate the role of natural variability, circulation, and other factors in the local event; it treats global temperature as the key explanatory fingerprint.

The article illustrates the concern with a deliberately absurd test. Pielke applies the same kind of statistical procedure to Major League Baseball home-run totals and finds a correlation with global mean surface temperature. He then produces an attribution-style comparison suggesting that the 2019 home-run record could not have occurred in a 1900 climate. The point is not that climate models literally claim climate change causes home runs. The point is that a statistical relationship between two trending quantities, combined with a counterfactual curve shift, does not by itself establish a physical causal relationship.

He makes the same point by substituting global patent applications for temperature in a replication-style exercise involving rainfall associated with Typhoon Hagibis. If the procedure can generate a striking counterfactual result using a variable with no plausible physical connection to rainfall, then the method must be evaluated not merely by its mathematical output but by the physical basis of the relationship, the treatment of competing influences, and the robustness of the result.

Pielke’s article describes the WWA advocacy orientation. The key point is that a press-release headline about climate change making a particular disaster more likely is not the same thing as a definitive causal demonstration. WWA is funded by climate advocacy philanthropies: Grantham Foundation, the European Climate Foundation and the Bezos Earth Fund.  A method’s assumptions, event selection, data choices, model skill, treatment of uncertainty, and physical plausibility all matter.  It is naïve to presume that the source of their funding does not affect the selection of those parameters.

My weather-versus-climate resource page has documented comparable concerns with treating unusual weather as conclusive proof of a climate-driven trend. It notes examples in which advocates have attributed floods or heat events to climate change without adequately considering the particular meteorological circumstances, historical context, or the role of natural patterns.[102]

The appropriate response is neither to insist that all attribution work is worthless nor to accept every attribution headline without scrutiny. The appropriate response is to insist on transparency and proportionality. A statement that climate change altered the probability of a class of events is different from a claim that climate change caused a particular event. Both are different from the further claim that New York’s extraordinarily expensive energy mandates will noticeably reduce the risk of similar local events within any meaningful planning horizon.

Climate policy cannot repeal weather

The public often hears an implicit promise: make enough changes to the energy system and communities will experience fewer floods, fewer storms, fewer heat waves, and fewer disasters. That promise is misleading.

New York’s emissions are a tiny fraction of global emissions. Even complete achievement of the Climate Act’s emission targets would not produce a measurable change in global temperature or detectable changes in the frequency or intensity of weather events experienced by New Yorkers. That does not mean New York has no obligation to pursue sensible environmental policy. It means that state policy should not be sold as a near-term weather-control program.

A prudent climate-risk strategy should put much greater emphasis on measures that reduce vulnerability regardless of the future trajectory of temperature: reliable power during heat waves and cold spells; resilient transmission and distribution systems; floodplain management; upgraded drainage; better weather forecasting and warning systems; hardening of critical infrastructure; emergency preparedness; and protection for people least able to cope with severe weather.

Those investments can produce benefits whether the next severe event is shaped principally by natural variability, long-term climate change, poor land-use decisions, aging infrastructure, or some combination of all four. Adaptation and resilience are not alternatives to prudent emissions reductions; they are essential because weather hazards exist now and will continue to exist under every plausible energy-policy scenario.

A genuinely pragmatic approach

New York should reduce emissions where reductions are demonstrably cost-effective and do not compromise reliability. It should retain existing zero-emission generation, particularly nuclear and hydropower. It should encourage technological innovation, grid modernization, efficiency, and demand flexibility. It should not insist on zero emissions.  It should invest heavily in adaptation and resilience. It should also avoid mandates that force consumers to bear unlimited costs for a system that has not demonstrated it can operate reliably through adverse weather.

The required standard should be straightforward:

  • Do not retire dispatchable generation before dependable replacement capacity is operating.
  • Require rigorous full-system cost accounting, not selective generator-level comparisons.
  • Set enforceable affordability safeguards and identify who will pay.
  • Demonstrate reliability during extended low-wind and low-sun periods, extreme heat, extreme cold, and transmission contingencies.
  • Evaluate land, habitat, and community effects as seriously as combustion emissions.
  • Treat weather-attribution claims as evidence to be scrutinized, not as slogans that settle a policy debate.
  • Invest in adaptation measures that reduce risks today regardless of the uncertain contribution of climate change to any individual event.

Climate policy deserves rigorous analysis precisely because the consequences are so important. The public should not be asked to accept dramatic claims of weather causation on faith, nor should it be asked to accept an unprecedented restructuring of the energy system without proof that the resulting system will be reliable, affordable, and environmentally beneficial.

My core concern is not that climate change is irrelevant. It is that energy and climate policy must be based on a realistic comparison of risks and benefits. If the cure creates unaffordable energy, reliability failures, unnecessary environmental damage, and little detectable influence on future weather hazards, then policymakers have an obligation to change course.

Acadia Center’s RGGI Fact Sheet Doesn’t Set the Record Straight — It Rewrites It

On September 9, 2026, Acadia Center published a fact sheet titled “Regional Greenhouse Gas Initiative (RGGI) Impacts in ISO New England: Setting the Record Straight on Costs and Benefits.” Its “bottom line” is that RGGI is a $4-to-1 winner for New England ratepayers — $445 million in 2025 auction proceeds projected to return $1.3 billion in lifetime energy-bill savings, comfortably beating the $815 million ISO-NE estimates RGGI added to 2025 wholesale costs. The fact sheet closes by urging ISO-NE states to keep championing the program and to finish implementing the Third Program Review’s tighter caps.

I have spent the summer documenting exactly this kind of accounting in New York, where the Department of Environmental Conservation (DEC) and New York State Energy Research & Development Authority (NYSERDA) defended the same Third Program Review amendments with a “nearly 6-to-1” ratepayer savings ratio. Acadia’s fact sheet uses the identical structure — a modeled, lifetime, participant-side savings figure set against a single year of narrowly defined cost — and it does so in the same week that RGGI’s own auction results undercut its “manageable costs” framing. Setting the record straight requires looking at both halves of the ledger, not just the half that makes the program look good.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

Bad timing: Auction 73 landed the same day

Acadia’s fact sheet is dated September 9, 2026 — the same day RGGI held Auction 73. The results came out two days later: a clearing price of $37.65 per allowance, up $2.65 from Auction 72’s $35.00 record set just three months earlier, and up 296 percent from the $9.30 clearing price at the first full auction of Governor Hochul’s tenure in September 2021. The top bid at Auction 73 was $190 per allowance — five times the clearing price — which is not what a market in balance looks like. I covered this in RGGI Auction 73: The Clearing Price Question Is Answered, following up on RGGI Update and the Auction Clearing Price Question.

Acadia’s fact sheet was written before the auction set its second consecutive record high, with the program’s own price-relief mechanism — the Cost Containment Reserve (CCR) — already exhausted for the year by the March 2026 auction. A fact sheet arguing that RGGI’s costs are modest and well-managed needed to grapple with that trajectory. It doesn’t mention it at all.

The core accounting problem: modeled lifetime savings vs. one year of cost

Acadia’s $1.3 billion savings figure is explicitly a projection, not a measured result. Its own Endnote 3 says so: “2025 investment and outcomes data are not yet available, this analysis applies real data from [the] 2024 report”.  The reports calculates the ratio of proceeds each state invested in each program category, and the lifetime savings each ratio historically returned — to 2025’s actual proceeds total. In other words, Acadia took last year’s return ratios and multiplied them by this year’s revenue. That’s a projection built on an assumption of continuity, not a report of what actually happened.

This is the same structural move the DEC and NYSERDA made when they defended New York’s RGGI amendments with a “nearly 6-to-1” ratio: $12.334 billion in what NYSERDA itself labels “Energy Bill Savings to Participating Customers” against $2.188 billion invested. When I went through the Technical Support Document behind that number, the qualifications mattered enormously. The $12.334 billion figure is a modeled, expected-lifetime estimate. It includes projects still in the pipeline that are not yet operational. It has generally not been adjusted through evaluation, measurement, and verification (EM&V). And it is compared only against historical program expenditures, not against the revenues collected or the program’s full cost. Acadia’s multipliers — 4.5x for energy efficiency, 8.2x for clean energy, 1.22x for electrification, 1.0x for bill assistance — are the same kind of lifetime, model-derived ratio, applied here to a single year of proceeds rather than verified against actual outcomes.

Acadia also compares apples to oranges on the timing. The $1.3 billion is a lifetime figure — savings that compound over the 15-to-20-year measure life of efficiency and clean-energy programs. The $815 million cost is a single year, 2025 only value. Stacking a multi-year benefit stream against one year of cost is not a real return-on-investment calculation; it overstates the ratio by construction. A colleague of mine, who prefers to remain anonymous, framed the broader problem well: this kind of program takes a dollar from the consumer now and returns a fraction of that dollar’s value later, through delayed and partially administered programs — with people who don’t qualify, can’t front the upgrade cost, or don’t navigate the application process absorbing the shortfall in full, indefinitely. Discount a delayed, diminished, partially realized return to present value, and Acadia’s 4-to-1 ratio — like NYSERDA’s 6-to-1 — looks considerably less generous than advertised.

The missing piece: the wholesale-market cost adder

Acadia’s entire cost side of the ledger is ISO-NE’s estimate that carbon pricing programs added $815 million to New England’s 2025 wholesale electricity costs, or roughly $55 per household per year. ISO-NE’s own 2025 Annual Markets Report is worth reading directly here, because it confirms the mechanism I have been documenting in New York: the wholesale-market cost of carbon compliance is larger than the direct cost of the allowances themselves. ISO-NE’s report separately estimates the direct cost of carbon allowances purchased — based on spot allowance prices — at about $668 million, versus the roughly $1.1 billion (all carbon programs) added to total energy market costs. The report explains why those two numbers differ: “the total cost of carbon allowances is lower than the total cost to the energy market because when fossil fuel-fired generators are on the margin, the inclusion of carbon costs raises the market clearing price” paid to every dispatched resource in that interval — not just the unit that bought the allowance.

ISO-NE’s own numbers show the same markup that I found in New York — roughly a 65 percent gap between the $668 million direct allowance cost and the $1.1 billion total energy-market effect for 2025. Acadia cites the $815 million RGGI-specific share of that already-marked-up total as its entire cost figure, which is more honest than counting direct allowance purchases alone. But it still stops at the energy-market adder ISO-NE models.  It does not address capacity-market or other second-order effects, and it treats that single number as the full and final cost against which a multi-year, multi-program savings projection should be judged. If the wholesale mechanism is real enough for ISO-NE to model explicitly, it deserves more scrutiny than a single citation before being set against a rosy, projected benefit.

There’s also a regional wrinkle Acadia doesn’t address: this cost doesn’t stay inside RGGI’s borders. I looked at this question for New Hampshire’s potential exit from RGGI and found that even a state that leaves the program, or a ratepayer who receives no direct benefit from RGGI-funded programs, still pays an embedded RGGI cost on any imported electricity from RGGI-compliant states, because the marginal generator setting the regional clearing price is often RGGI-covered. Cost and benefit are not neatly contained within each state’s own ledger the way Acadia’s state-by-state table implies.

Averages hide who actually pays and who actually benefits

Acadia’s own Table 2 shows the “4-to-1” story doesn’t hold uniformly. Vermont receives $9.45 million in proceeds and shows zero recorded clean-energy or electrification savings in the table — its entire $42.1 million total comes from the energy-efficiency category alone. New Hampshire gets $65 million in direct bill assistance and comparatively little efficiency benefit relative to its proceeds. Massachusetts, with the largest efficiency infrastructure, drives most of the region’s projected savings. The multipliers Acadia uses aren’t universal constants.  Instead, they depend entirely on which category a state’s dollars land in and how mature that state’s program infrastructure already is.

That variance matters because the cost side doesn’t vary the same way. The $4-to-5-per-month wholesale cost adder is charged to every ratepayer, uniformly, embedded in the price of every kilowatt-hour, whether or not that household ever benefits from an efficiency rebate or a bill-assistance program. The offsetting “savings” are conditional on eligibility, program capacity, and successful completion of an application process. A household that doesn’t qualify for a program, can’t front the money for an efficiency upgrade, or doesn’t live in a service territory where a credit applies still pays the RGGI-driven cost in full, with nothing returned. Averaging across six states and four program categories smooths over exactly the distributional problem that determines whether any individual ratepayer actually comes out ahead.

How much of the 37 percent reduction is actually RGGI?

Acadia states plainly that RGGI “has driven CO2 reductions of 37% since 2001 across New England power plants,” and repeats the claim in its conclusions. Firstly, RGGI started in 2009 so RGGI had no impact until then.  Secondly, I’ve run the equivalent calculation for New York, using the state’s own reported cumulative program benefits, and found that RGGI-funded investments and programs account for only about 4.7 to 8.7 percent of the observed power-sector CO2 reduction since the program began. The overwhelming majority of the historical reduction is attributable to fuel switching from coal and oil to lower-emitting natural gas — a transition that happened for reasons largely unrelated to RGGI’s reinvestment programs, and one that offers little room to repeat.

Acadia’s own Table 3 makes the same point for New England, probably without meaning to. It shows natural gas now accounts for 95.4 percent of RGGI-covered CO2 emissions in ISO-NE, with oil contributing just 3.7 percent. The coal-to-gas switch that produced most of the historical emissions decline has already happened; there’s essentially no coal left to switch away from in this region. Which raises the obvious question Acadia doesn’t ask: if further RGGI-covered emissions reductions now require displacing gas generation directly, rather than riding a fuel-switching wave that has already run its course, what is the actual mechanism — and cost — of the next round of reductions the program claims credit for? A 37 percent historical reduction that mostly happened for other reasons isn’t a reason to expect the next 37 percent to come as easily, or as cheaply.

The oil-burn section: refuting an argument nobody serious is making

Acadia devotes a full page to rebutting the idea that New England’s wintertime oil burn is the primary driver of RGGI costs, concluding — correctly, based on their Table 3 — that natural gas is responsible for 26 times more RGGI-covered emissions than oil in 2025. That’s a fine technical point, but it isn’t the critique that matters. The substantive concern with RGGI, in New York and everywhere else, is the allowance price trajectory and the wholesale-market mechanism that embeds that price into every consumer’s bill — not the fuel mix of the marginal generator in any given hour. Spending a full section rebutting a weaker, secondary claim about oil, while never engaging the allowance-price-and-market-mechanism critique that program skeptics actually make, is a rhetorical choice. It answers a question nobody serious is asking instead of the one that’s actually on the table.

It’s also worth noting, in passing, what Table 3’s own footnote admits: wood and refuse-derived generation are exempt from RGGI’s cap entirely, despite being more emissions-intensive per megawatt-hour than oil and producing more electricity than oil in New England — 2,012 GWh and 2,563 GWh respectively, against oil’s 1,147 GWh. A cap that carves out fuels more emissions-intensive than the one being singled out for scrutiny is not the airtight accounting Acadia’s framing implies.

The cap trajectory: “manageable” is getting harder to say with a straight face

Acadia’s closing recommendation is that ISO-NE states should keep championing RGGI and finish implementing the Third Program Review’s steeper caps. That recommendation doesn’t engage with what’s happening in the allowance market right now. RGGI’s own price-relief valve, the Cost Containment Reserve, was fully exhausted for 2026 by the March auction — months before the year’s compliance deadline. The Auction 73 clearing price exceeds the 2036 CCR1 trigger price and the 2030 CCR2 trigger price and that suggests that in future years both CCR allocations will be exhausted in the first quarterly auction.  That means the CCR will not meaningfully reduce costs.  On August 21, 2026, RGGI’s independent market monitor, Potomac Economics, released an unprecedented special report on the second-quarter 2026 supply-demand balance, roughly eleven weeks after the Auction 72 price spike, apparently to reassure the market. Instead, it confirmed that compliance entities and investors are increasingly hoarding allowances rather than selling them as compliance deadlines approach, that investors hold 68 percent of the allowance surplus with no obligation to sell below whatever price the market has already shown it will bear, and that Virginia’s return to the program (it resumed participation July 1, 2026) adds less new supply than the new demand it represents. Most tellingly, the report explicitly declined to address whether the Third Program Review’s post-2027 cap trajectory — more than 10 percent annual reductions in the regional budget from 2027 through 2033, a pace the program has never sustained historically — is even sustainable, calling that question “beyond the scope” of the report. 

Auction 73 answered the question the market monitor wouldn’t. The cap tightens further, the CCR is gone for the year, Virginia is a net new claim on the allowance bank rather than a source of relief, and the price cleared at a record $37.65 anyway, on one of the largest single allowance offerings in the program’s history. If the tool specifically designed to prevent this kind of price escalation is already exhausted, and the program’s own independent monitor won’t vouch for the tightening path immediately ahead, then “continue to champion the program and keep tightening the cap” is not the reassuring, record-straightening conclusion Acadia presents it as.

What would actually set the record straight

Proponents of RGGI claim the program has been a success.  It’s an argument that this program’s accounting doesn’t support the “clear win for ratepayers, no real cost” story currently being told about it — in New York, and now in New England. If RGGI states and their advocates want to demonstrate a real, net ratepayer benefit rather than a modeled one, three things would help: publish realized, EM&V-verified savings instead of projected lifetime estimates built on the prior year’s ratios; have ISO-NE and NYISO calculate the full wholesale-market cost adder using the hourly dispatch data only grid operators have, rather than relying on a single annual estimate cited without independent scrutiny; and report the cost per ton of CO2 actually achieved through RGGI-specific investment, isolated from the fuel-switching-driven reductions that occurred for entirely separate reasons.  Acadia’s own fuel-mix data shows have largely already happened. Until that accounting exists, an aggregate, multi-year “4-to-1” ratio measured against one year of narrowly scoped cost is not setting the record straight. It’s the same rhetorical move New York regulators made with a bigger number, dressed for a different region.

RGGI Auction 73 Clearing Price Question Is Answered

On September 3 I published an article about Regional Greenhouse Gas Initiative (RGGI) costs that contradicted the energy affordability messaging of Governor Hochul.  A week ago, I had an article published at Watts Up With That which summarized recent articles here and posed a simple question: would the Regional Greenhouse Gas Initiative’s Auction 73 clearing price exceed the Auction 72 record of $35.00 per ton? The answer arrived this week, and it wasn’t close. RGGI announced that Auction 73 cleared at $37.65 per ton — $2.65 above Auction 72, and yet another record for the program.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

What RGGI reported

The RGGI press release described the results this way:

NEW YORK — The eleven participating states in the Regional Greenhouse Gas Initiative (RGGI), the nation’s first market-based regulatory effort to reduce greenhouse gas (GHG) pollution, today announced the results of their 73rd auction of carbon dioxide (CO2) allowances. 28,537,847 CO2 allowances were sold at the auction at a clearing price of $37.65. This includes an initial offering of 27,389,847 allowances and 1,148,000 CCR allowances. The allowance offering included a supply of 5,740,000 allowances from Virginia, which resumed RGGI participation on July 1, 2026. Bids for the CO2 allowances ranged from $2.69 to $190 per allowance.

Two details in that paragraph matter more than they might look at first glance. First, the auction included 1,148,000 Cost Containment Reserve (CCR) allowances, and Virginia’s re-entry contributed 5,740,000 allowances to the offering — the two factors I’d flagged in my earlier post as the only real candidates for near-term relief. Second, the top bid was $190 per allowance, five times the clearing price. That kind of bid spread is not what a market in balance looks like.

Why this result was predictable

Regular readers know I have been documenting this trajectory since summer. The short version: RGGI’s allowance price has more than tripled since the start of Governor Hochul’s tenure, and every structural signal pointed toward more of the same rather than relief in the latest auction.

In Hochul and RGGI Affordability, I quantified the wholesale-market effect of RGGI allowance costs and showed why it undercuts the Governor’s affordability messaging. New York’s electricity market pays every accepted generator the market-clearing price for a given interval. When an emitting generator sets that price, its RGGI allowance cost is embedded in the bid and gets paid to every dispatched resource in that interval — including non-emitting and imported resources that bear little or none of the underlying RGGI cost. That post showed the RGGI allowance price rising from $9.30 per ton at the first full auction of Hochul’s tenure to $35.00 at Auction 72 — a 276% increase. At the Auction 73 price of $37.65, that increase is now 296%. For a typical residential customer, the RGGI-attributable share of the electric bill was around 4.2% in 2024; at $37.65 it is roughly 7.8%.

I also covered the special report RGGI’s own market monitor, Potomac Economics, released on August 21, 2026 — the Report on the Supply and Demand for RGGI CO2 Allowances: Second Quarter 2026 — in RGGI’s Market Monitor Confirms the Scarcity I’ve Been Tracking. I believe that report’s timing, roughly eleven weeks after the record $35 auction, was meant to calm the market. Instead it confirmed that 2026’s CCR allowances were fully exhausted, that compliance entities and investors are increasingly hoarding rather than selling allowances as the compliance deadline approaches, that Virginia’s return adds less new supply than the demand it brings, and — most tellingly — that the report declined to address whether the steep post-2027 cap trajectory is sustainable, calling that question “beyond the scope” of the report. Given that the auction price went up anyway, whatever calming effect was intended did not materialize.

Heading into Auction 73, secondary-market pricing was already telling the same story. Argus Media reported 2026-vintage RGGI allowances trading in the high-$30s to around $40 per short ton in mid-to-late August (Argus Carbon), with December 2026 futures trading even higher. The market monitor’s own Q2 2026 report showed that investors — who have no obligation to sell — held 68% of the allowance surplus, with little incentive to release allowances below the price the market had already demonstrated it would pay. The 2026 CCR was gone before the auction. Virginia’s re-entry was always a net new claim on the bank, not a source of relief. A larger Auction 73 offering had the opportunity to absorb that pressure; instead, it simply confirmed how much latent demand exists, since the price cleared above $35 despite the bigger offering.

Costs are not hypothetical

Put together, this is a consistent story, not a series of isolated data points. RGGI’s own cost-containment mechanism — the CCR, which is supposed to release additional allowances once prices cross a trigger — was exhausted as soon as 2026’s allowances became available, months before the compliance deadline. The regional cap is scheduled to tighten by more than 10% of the 2025 budget every year from 2027 through 2033, a pace the program has never sustained historically. Virginia’s re-entry adds demand faster than it adds supply. And New York adopted its conforming rule amendments in August without grappling with any of this, leaning on cost-impact modeling that predates the price spike and a ratepayer-benefit claim that ignores the wholesale market cost adder entirely.

None of this is abstract for consumers. My estimates put the total New York consumer impact of RGGI — direct allowance costs plus the wholesale market cost adder — at $1.1 to $3.4 billion annually at a sustained $37.65 allowance price, more than double the direct-allowance-cost figure that state messaging emphasizes. Scaled across all eleven RGGI states, the same mechanism plausibly adds several billion dollars more. That is the real price of a program whose defenders describe rising auction revenue as a “big opportunity” for new spending rather than what it actually is: a cost signal ratepayers are already absorbing.

Where this leaves the debate

When I posed the question of whether the price would exceed $35, I noted that every available signal pointed toward continued upward pressure rather than relief. Auction 73 confirmed it. That is real-time evidence that the price trajectory regulators have not acknowledged is not leveling off — and one more sign that the states’ own cost-containment tools, the mechanism regulators cite as evidence that consumer costs will stay manageable, can no longer do the job they were designed to do. Given these cost impacts, it is past time to pause RGGI.

Terra Praxis Says Repower New York with Nuclear — I Mostly Agree

Update 9/14/26 – I changed the link to the discussion paper to the final version.  At the end of the document I also have added a response to this article by Isuru Seneviratne, Director, Lucid Catalyst who alerted me to the document in the first place.

Terra Praxis, a nonprofit focused on accelerating advanced nuclear deployment, has published a discussion paper called “REPOWER New York.” This post summarizes what the paper argues, what I found when I used Perplexity AI to check its numbers, and where I agree and disagree with its bottom line.

I am convinced that implementation of the Climate Leadership & Community Protection Act (Climate Act) net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks. The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

What the paper argues

The core idea is straightforward: instead of building new nuclear plants one at a time as tailored, site-specific projects — which is how the U.S. nuclear industry has approached every reactor built in the last twenty years — New York should commit to a repeat-build program that puts the same reactor design on multiple sites in sequence. The paper argues the best sites are New York’s retired and at-risk fossil and industrial locations: former coal and oil plant sites and the state’s remaining single-unit nuclear plants, where transmission interconnections, water rights, and a trained workforce already exist. Reusing that infrastructure, the paper argues, avoids years of new transmission siting and permitting that a greenfield project would need.

The paper’s other central argument is about what it calls “Dispatchable Emissions-Free Resources,” or DEFRs — a term NYSERDA’s own Zero by 40 study uses for resources that produce no emissions, can be dispatched on demand, and can operate reliably through extended periods of low wind and solar output. The Zero by 40 study evaluated seven DEFR candidates: hydrogen combustion, renewable natural gas, advanced nuclear, carbon capture, geothermal, long-duration storage, and virtual power plants. The paper’s argument, and one that I have long also argued, is that nuclear is the only one of those seven that is commercially proven at scale, can be built to a firm schedule once a design is chosen, and does not depend on a fuel supply chain, storage duration breakthrough, or geologic accident of location the way the other six do. Hydrogen and RNG combustion depend on fuel volumes and delivery infrastructure that don’t yet exist at the needed scale. Geothermal in New York is site-limited. Long-duration storage and carbon capture are not commercially deployed at the scale this problem requires. Nuclear is the one DEFR you can actually plan to build, in a specific quantity, on a specific schedule, if you’re willing to pay for it and manage the program well.

That is the paper’s real argument, and it is the argument I want to spend the rest of this post on, because I think it is largely right, with one important caveat.

Where I agree: nuclear power is the DEFR you can develo as needed

New York’s own planning documents already say we need a lot more dispatchable, emissions-free capacity than we currently have. The Joint Utilities’ CGPP Cycle 1 Report filed with the PSC models a scenario with roughly 5.5 GW of nuclear-like DEFR capacity available by 2042 against a scenario without it, and finds the difference is stark: total system capacity of about 100,000 MW with that DEFR resource in the mix, versus about 130,000 MW without it, to serve the identical peak load. Put another way: every megawatt of firm, dispatchable capacity you don’t build gets replaced by roughly five to six megawatts of wind, solar, and storage nameplate capacity, because those resources aren’t available when you need them most. That 30,000 MW gap is the entire argument for DEFRs in one number, and it is New York’s own modeling, not Terra Praxis’s.

The Options Paper adds the piece that actually matters for a decision-maker: it prices out what that capacity costs to build. Under NYSERDA’s own analysis, a repeat-build fleet — its “Option 3: Multiple Sequential Pipeline Procurements” — carries an all-in price of roughly $12,800 to $13,400 per kilowatt in the Base Case, once the state provides financing support that gets private capital comfortable with the schedule risk. That is a real number I would not have expected NYSERDA to publish so plainly, and it is meaningfully lower than what the same paper shows for financing the same reactors with no state support at all — where the price nearly doubles, largely because private capital demands a much higher return to bear all the construction schedule risk itself. The point the paper is making, correctly, is that most of what makes nuclear expensive in the U.S. is not the reactor hardware. It is financing risk stacked on top of one-off procurement. That is consistent with what happened at Vogtle, where a program that started at roughly $14 billion for two units ended up above $30 billion, largely from schedule slip rather than design changes.

I have spent years arguing that New York’s decarbonization mandates keep underpricing the cost of firm capacity and overselling the reliability of wind and solar. If the state is serious about replacing fossil generation without wrecking reliability, a resource you can order in a known quantity, on a plannable schedule, at a knowable cost — using a design that has already been licensed and built elsewhere — is the only thing on that list of seven DEFRs that meets that bar today. I support developing enough nuclear capacity to cover the state’s baseload needs precisely because it is the viable alternative to the current plan, which is to keep building utility-scale wind and solar and hope storage and transmission catch up in time. They haven’t, and there’s no evidence in the state’s own filings that they will on the current timeline. A large, planned nuclear buildout is the one path I’ve seen that gets New York to a genuinely low-emissions grid without requiring tens of thousands of additional acres of utility-scale renewables and the transmission to move that power from where the wind blows to where the load is.  Moreover, the cumulative environmental impact of that development is frightening.

Where I part ways with the paper: nuclear powr is a baseload solution, not an everything solution

Here is where I think the paper, and a lot of nuclear advocacy generally, overreaches. Nuclear is excellent at running flat out, all the time, for decades. That is exactly what baseload means, and it’s exactly why it’s the right tool for the DEFR problem: New York needs a large, firm floor of generation that doesn’t disappear when the wind stops or the sun sets. But the state’s electricity demand isn’t flat. There’s a large gap between the baseload floor and the peak load on the hottest afternoon of the summer, and that gap changes hour to hour and season to season. Nuclear plants are not economical, and are not designed, to ramp up and down to chase that kind of load — you don’t want a billion-dollar asset with decade-long payback economics cycling on and off to follow a few hours of afternoon peak demand a few dozen days a year.

That’s the role I think natural gas still should play, and I don’t think the paper’s framing — where the endgame is nuclear covering essentially all of the state’s electric energy — grapples with this. Peaking capacity and some intermediate load are jobs gas turbines already do well, at low capital cost, with fast start times, exactly because they only need to run a fraction of the year. Trying to cover that same peaking and intermediate role with more nuclear capacity means building reactors sized for the worst afternoon of the year and then running them well below capacity factor the rest of the time — which is the opposite of the economics that make repeat-build nuclear affordable in the first place. The paper’s own numbers show why: the value of a nuclear asset comes from running it as close to full output as possible for as many hours as possible. Ask it to load-follow like a gas peaker and you’ve thrown away the cost advantage the whole paper is built around.

Where I’d like to see more natural gas going forward isn’t in new electric generation, though — it’s in two other uses the paper doesn’t mention at all. The first is transportation combustion substitution: natural gas in place of diesel in trucks and other heavy vehicles does something wind, solar, and battery storage cannot do on any realistic timeline, which is cut inhalable particulate emissions from diesel exhaust at the tailpipe, immediately, in the communities where those trucks operate. That’s a real, measurable air-quality benefit — the kind I spent a career studying — and it doesn’t show up in the grid-decarbonization accounting either the state’s Energy Plan or this paper cares about, because it isn’t a grid benefit at all. The second is on-site use in homes and businesses, where high-efficiency gas furnaces and other direct-combustion appliances remain the cheapest and most energy-efficient option for space heating and process heat, out-performing electric-resistance and heat-pump alternatives on delivered cost and, in cold-climate operation, on efficiency as well. There is one other advantage of residential gas use – resiliency. I have lived in my home for 45 years and survived two major electric blackouts related to weather in no small part because natural gas provided heat, hot water, and cooking support during the multi-day electrical outage. I have never had a natural gas service outage.

A serious New York energy strategy should treat nuclear and gas as doing different jobs for different reasons: nuclear for the emissions-free baseload floor so we don’t have to keep chasing utility-scale renewable buildout, and gas for electric grid support, the transportation and on-site combustion roles where it beats the alternatives on cost, efficiency, or public health today. Trying to make nuclear substitute for those roles, or forcing electrification onto them by mandate, is asking one resource to solve problems it wasn’t built to solve, at a cost the repeat-build economics in this paper’s own tables were never meant to carry.

The fine print: what I’d flag on the numbers

I did not have time to check all the numbers in the report, so I used Perplexity AI for that purpose.  With the caveat that I did not check all the Perplexity results I agree with the AI response that did not find anything fabricated in the paper — every figure checked traces back to a real NYSERDA filing, PSC proceeding, DOE study, or nuclear project cost record, and in most cases to the specific page or table cited. That’s a high bar for a 32-page advocacy paper with 94 endnotes to clear, and it did.

Bottom Line

New York’s own modeling says the state needs a large amount of dispatchable, emissions-free capacity that wind, solar, and storage cannot reliably provide, and nuclear is the only one of the seven DEFR candidates NYSERDA itself evaluated that is proven, buildable at scale, and priceable today. I support building enough nuclear power to cover the state’s baseload precisely because it is the one path that lets New York stop chasing an ever-larger buildout of utility-scale renewables and the transmission needed to move that power around. But baseload is not the whole grid, and it’s certainly not the whole energy economy.

Natural gas should still have a legitimate future role in peaking and intermediate generation that nuclear economics were never designed to serve.  I believe that it is even more valuable to directly displace diesel in vehicle applications, where it cuts the inhalable particulate emissions that diesel exhaust puts directly into the air people breathe. In addition, I think natural gas provides on-site services cheaper and with better resiliency than electric alternatives so it should remain an acceptable option.   A nuclear buildout that solves the baseload problem, alongside a gas fleet doing the jobs it’s actually good at, is a more honest — and more affordable — energy strategy than relying on wind, solar, and energy storage to provide electricity to do everything. 

Response 9/14/26: Isuru Seneviratne, Director, Lucid Catalyst

There’s one place where I think the paper is being read as saying the opposite of what it argues, and one place where you’re simply right.

We don’t argue for low-capacity-factor nuclear. It’s the reverse, and it’s the core of the siting case: our analysis of a thirteen-site, 24 GW coal fleet running at just 10–17% capacity factor found that repowering it to 95% would raise that country’s entire electricity generation by over 170%. Low capacity factor is the problem REPOWER NY is trying to solve, not a duty cycle it proposes. A retired plant’s interconnection is permitted and sized for continuous output, which is exactly why it suits a machine that runs flat out.

Where we do argue for expanding nuclear’s role is not sideways into peaking but outward into industrial heat and power. Roughly four-fifths of New York’s final energy demand sits outside the power sector — process heat, fuels, industrial loads — and those emissions cannot be abated by cleaning up the grid, because the fuel is burned on site. A repowered site can deliver electricity and process heat, hydrogen, and district heating from the same asset. That’s a higher-utilization use, not a lower one, and it’s a large market.

The paper’s focus is narrower, and addresses an issue where New York needs help: how to make nuclear commercially financeable through rational industrial policy. Costs, time, and the uncertainties of both fall with a standardized repeat-build order book at the fewest viable sites, and further as delivery moves off bespoke site construction — the difference between a program that needs permanent subsidy and one that doesn’t. Expanding nuclear’s use case to industrial energy enables the supply chain, labor, and industrial capacity investments necessary to make nuclear cheaper.

I do agree that one sentence in “the carbon case” implies “nuclear can do it all”: “Firm nuclear capacity sited at a retired fossil plant can displace natural gas plants otherwise needed to fill in when output from variable renewables drops.”

Your criticism is fair since REPOWER NY asserts the capability without naming the machines. Nuclear is already a dispatchable energy source in practice, not just in theory (“Nuclear is a Dispatchable Electricity Source” by Nuclear New York, filed with the Department of Public Service in November 2023). See also the “Nuclear Energy” section here (Nuclear New York filing with the DPS, March 2024).

I’d push back on the premise that dispatchability and high capacity factor are in tension. For several of the technologies now in operation or under construction, they aren’t. Take Natrium, which TerraPower is building at a retiring coal plant in Kemmerer, Wyoming, for 2031. Its reactor is sized to run continuously at 345 MW and does exactly that; the plant stores the heat in a nitrate salt tank and the turbine draws on it to deliver anywhere from 100 to 500 MW, ramping at 40 MW a minute and holding full output for five and a half hours. The reactor never cycles. The salt tank does the following. You get the peaking service without touching the capacity factor that the economics depend on — which is why PacifiCorp is contracting for the 500 MW Kemmerer output and, in its 2025 Integrated Resource Plan, continues to evaluate two further Natrium units in Utah by 2035. See PacifiCorp and TerraPower on the additional units and the 2025 Integrated Resource Plan (Utah, Volume I).

On gas keeping the peaker role, I largely agree with you, and REPOWER NY doesn’t say otherwise — it doesn’t say anything. The words “peaking”, “peaker” and “load-following” appear nowhere in it. Fast-start plant covering a few hundred hours a year is a job gas does well, and the case for siting nuclear at retired (and operating) fossil and industrial sites does not rest on it.

NYSERDA Admits Build-Ready Program Failure in Five-Year Review

I want to thank Alexandra Fasulo (@alex_fasulo on X) and Amy Lavine for finding NYSERDA’s just-released “Build-Ready Program Five-Year Review, October 2020–September 2025.” This is a remarkable document because it is a rare case of a New York State clean-energy agency admitting, in its own words, that one of its signature programs did not work and recommending that its ratepayer-funded version be shut down.

I am convinced that implementation of the Climate Leadership & Community Protection Act (Climate Act) net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks. The opinions expressed in this article do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

What the Build-Ready Program Was Supposed to Do

The Build-Ready Program grew out of the Accelerated Renewable Energy Growth and Community Benefit Act, which directed the New York State Energy Research and Development Authority (NYSERDA) to identify landfills, brownfields, abandoned industrial sites, and other previously developed properties, take them partway through the development process, and then auction the “build-ready” sites to private developers. The Public Service Commission approved a $71.8 million budget for the effort in October 2020, drawing on up to $50 million from the Clean Energy Fund (CEF), with the expectation that the program would eventually become “evergreen” — self-sustaining from auction proceeds. The Order also envisioned NYSERDA advancing six large-scale renewable projects to solicitation every year starting in 2022 or 2023.

Five years and roughly $16.5 million in Clean Energy Fund draws later, the program has completed exactly one project: a 12-MW solar array on an iron ore tailings pile at the Benson Mines site in St. Lawrence County.

Section 3.1 Is Where the Report Gets Honest

The most important part of this document, in my opinion, is Section 3.1, “Program Challenges.” This is NYSERDA acknowledging, on the record, that the premise behind the program didn’t hold up. As the report puts it:

“The program was established on the hypothesis that New York State had readily available landfills, brownfields, and other previously utilized sites capable of supporting LSR energy projects throughout the State. During five years of program development work, however, the team found that very few sites in New York State both meet all of Build-Ready’s requirements (e.g. brownfield, landfill, no agricultural land, no competition with the private sector) and also can support economically viable LSR energy projects.”

Most previously developed sites turned out to be too small once wetlands and other non-buildable areas were excluded — frequently under 20 acres — and the adjacent land needed to expand them was overwhelmingly active farmland that program rules put off limits. The result: most identified Build-Ready projects came in under 10 MWac, well below the roughly 20 MWac NYSERDA considers the threshold for an economically viable large-scale solar project.

But the statement that should get the most attention from anyone who pays a New York electric bill is this one:

“Sites that met Build-Ready’s criteria also required significantly higher REC strike prices. Forecasts showed that future Build-Ready project REC prices could be roughly double those for Tier 1 greenfield projects. These high REC costs would place a significant financial burden on NYS ratepayers.”

Read that again. NYSERDA is telling the Public Service Commission, in its own five-year review, that the very sites that satisfied the Build-Ready Program’s siting criteria are the ones that would have cost ratepayers roughly twice as much per Renewable Energy Certificate as an ordinary Tier 1 greenfield solar project procured through the Clean Energy Standard. This is not a hypothetical concern raised by a critic of the Climate Act — it is the program administrator’s own forecast, buried in the “challenges” section of a report whose stated purpose is to justify winding the ratepayer-funded version of the program down.

Section 3.1 goes on to explain why: developing on previously used land is inherently more expensive than greenfield development because of environmental remediation, complicated site control (absent landowners, property liens), more intensive community engagement and permitting, specialized construction techniques to avoid ground penetration, and higher interconnection costs — all layered on top of smaller project sizes that limit the economies of scale developers need to absorb those costs. On top of all of that, the report notes that the federal One Big Beautiful Bill Act’s accelerated phase-out of the Investment Tax Credit — requiring construction starts before July 5, 2026, or in-service dates by the end of 2027 — will make it even harder for any future Build-Ready project to pencil out.

The Money

Table 1 in the report describes the financial reality. Through the end of 2025, NYSERDA projects total Build-Ready expenditures of about $16.57 million — split roughly evenly between salaries/overhead ($8.1 million) and technical, consultant, legal, and system-development support ($8.3 million) — against total revenues of only about $5.05 million, most of which came from the single Benson Mines auction. Table 2 shows that leaves roughly $11.5 million in Clean Energy Fund draws still to be repaid, which NYSERDA says it will cover from “non-ratepayer funding sources including but not limited to project development consulting payments, Regional Greenhouse Gas Initiative (RGGI), or other third-party payments subject to all required approvals and authorizations.”

Table 1. Build-Ready Program Actual and Forecasted Expenditures and Revenues through

December 31, 2025 from Build-Ready Program Five-Year Review, October 2020–September 2025

My primary concern with how New York invests RGGI proceeds in the NYSERDA 2026 RGGI operating plan amendment was that RGGI is an electric sector emissions reduction program, but NYSERDA does not prioritize emission reduction investments. This finding is evidence of yet another instance where RGGI auction revenues are being invested on programs that are not reducing emissions. The RGGI Operating Plan doesn’t specify a dollar amount, a mechanism, or a timeline. But it does make it clear how easily this could happen, because RGGI money already flows into the Clean Energy Fund as a matter of routine practice, not as an emergency backstop.

NYSERDA’s Draft 2025 Three-Year RGGI Operating Plan Amendment shows a line item called “Transfer to (from) Clean Energy Fund” that has already moved a cumulative $208.2 million in RGGI allowance-auction proceeds into the CEF through fiscal year 2023-24, with another $22.0 million budgeted for FY 2024-25 and $19.8 million for FY 2025-26 — bringing the all-time total to a planned $250 million (NYSERDA 2025 RGGI Operating Plan Amendment). On top of those permanent transfers, the same plan authorizes NYSERDA to use RGGI cash balances for “interfund liquidity management purposes” — temporary cross-fund borrowing of up to $200 million at any one time, with RGGI compensated at a pooled-investment interest rate, expressly so that it “will not interfere with RGGI work scope or program delivery.” In other words, NYSERDA has already built the plumbing to move RGGI allowance money into the CEF, both permanently and on a revolving basis, well before Build-Ready ever needed a bailout.

Put those two documents side by side and the concern comes into focus. RGGI allowance auction revenue is supposed to fund the specific categories set out in the RGGI Operating Plan — energy efficiency, renewable and non-emitting technologies, innovative carbon-abatement projects, and administrative costs, with a Climate Act mandate that at least 35 percent (and a goal of 40 percent) of the benefits flow to disadvantaged communities. In my opinion, those categories do not allocate sufficient revenues to emission reductions.  RGGI auction proceeds are forecast at roughly $305–$375 million a year through FY 2027-28, so $11.5 million is a rounding error against that total. But it is also money that will not be available for any of the programs the Operating Plan lists if it instead gets redirected, however indirectly, to closing out a siting program NYSERDA’s own report says failed to deliver economically viable projects. Because the CEF commingles funding from RGGI, System Benefits Charge assessments, and other ratepayer-funded sources, once RGGI dollars land in the CEF general pool, tracing exactly which dollars repay the Build-Ready draw becomes essentially impossible from the outside. That opacity is itself worth flagging: a ratepayer-funded program’s failure gets absorbed into a much larger fund without any public accounting of which RGGI-funded initiative effectively lost the $11.5 million.

The Bottom Line

NYSERDA’s own five-year review recommends that the Public Service Commission terminate the PSC-funded, ratepayer-backed version of the Build-Ready Program and confirm that NYSERDA will reimburse the roughly $16.5 million already drawn from the Clean Energy Fund. NYSERDA says it intends to keep operating a version of Build-Ready through 2030 using other funding, repositioned as an economic-development tool rather than a ratepayer-funded clean-energy procurement program. That pivot is a tacit admission that the original approach could not deliver comparably priced renewable energy at the scale the Order envisioned.

Given how often ratepayer-funded clean-energy programs are defended based on optimistic projections, it is notable to see NYSERDA’s own report concede that REC prices for its flagship siting program would run roughly double those of ordinary Tier 1 solar — and recommend pulling the plug on ratepayer funding as a result. In my opinion, this suggests that the optimistic  projections in the NYSERDA Scoping Plan and State Energy Plan could end up failing as well.

Credit again to Alexandra Fasulo and Amy Lavine for uncovering this report.  As Fasulo notes “Commercial solar cannot stand on its own in an open market. We’re paying for its lofty financial protections while they steam-roll our home rule and force these complexes into our rural communities.”

The Poll Says Don’t Raise Prices. RGGI Already Has.

The Empire Center for Public Policy recently released results from a statewide poll of 600 likely 2026 general-election voters, conducted by Cygnal, on New Yorkers’ energy and climate priorities.  The headline finding will not surprise anyone who has followed this blog: New Yorkers want lower emissions, but not if it costs them more money, and on that condition a plurality will not budge. I recently documented the RGGI allowance price and consumer cost history under Governor Hochul, and it is worth putting the survey and the numbers side by side, because they describe the same problem from two different directions — one is what New Yorkers say they want, and the other is what the RGGI program has actually been doing to their electric bills.

I have been involved in the RGGI program process since its inception and have worked on every cap-and-trade program affecting electric generating facilities in New York, including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since those programs began. I have been writing about problems with the RGGI program here for years.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to help research and draft this post.

What the poll found

The Empire Center summary lays out five findings from the survey:

  • When forced to choose between lower energy prices and lower greenhouse gas emissions, 24 percent of respondents prioritize price, 24 percent prioritize emissions, and the largest group — 42 percent — will only support emissions reductions if they do not raise energy prices.
  • Home-heating electrification is opposed by 63 percent of respondents and supported by just 30 percent, with opposition exceeding support in nearly every demographic group tested, including New York City Democrats.
  • Opinion on the state’s proposed New York Cap-and-Invest (NYCI) program is closely divided, and about one in five respondents statewide say they are simply unsure — in some subgroups the “unsure” share approaches 30 percent.
  • Sixty percent of respondents oppose allowing lawsuits against oil companies over climate damages, versus 21 percent in support.
  • On data centers, 59 percent want new facilities required to either build their own power or invest in local grid upgrades before drawing on the shared grid, and a third would bar new data centers outright — a sign that New Yorkers are already worried about who absorbs the cost of new electric demand.

The response across every question is the same: New Yorkers will tolerate climate policy, but only on the condition that it does not show up as a bigger number on their utility bill. That is precisely the condition that the RGGI program, as currently administered, does not meet.  It is also clear that the cap-and-invest plan is something most simply do not understand.

RGGI is already failing the poll’s own test.

The 42 percent plurality unwilling to pay higher energy prices for emission reductions in the Empire Center poll is not a hypothetical group waiting to render a verdict on some future policy. RGGI has been operating in New York since 2009, and I have tracked its price and cost trajectory in detail. When Governor Hochul took office in late August 2021, the most recent completed RGGI auction — Auction 52, on June 2, 2021 — had cleared at $7.60 per allowance. The first auction of her tenure, Auction 53 that September, cleared at $9.30. The most recent completed auction as of this writing, Auction 72 on June 3, 2026, cleared at $35.00, with all 18,349,699 allowances offered selling for total regional proceeds of about $642.2 million; New York’s share was $194.7 million on 5,563,451 allowances sold. The secondary market is currently trading above that $35.00 clearing price.

That is a $25.70 increase, or 276 percent, in the space of five years, and it happened with the direct participation of the state agencies the Governor oversees — the Department of Environmental Conservation (DEC), York State Energy Research & Development Authority (NYSERDA), and the Department of Public Service — all of which take part in RGGI program design, auction administration, and the cap-tightening decisions that determine how scarce allowances become. The recently finalized RGGI Third Program Review amendments, approved on August 5, 2026, lock in further reductions to the regional cap through 2037, with the steepest annual cuts scheduled from 2027 through 2033 — precisely the mechanism that has already pushed the allowance price up 40 percent in a single quarter this year.

Where the money actually goes

DEC and NYSERDA’s press release on the final amendments touts “nearly $12 billion in net ratepayer savings” against roughly $2 billion invested — a “nearly 6-to-1” return. I went through the Technical Support Document behind that number, and the qualifications matter enormously. The $12.334 billion figure is not verified, realized net ratepayer savings; NYSERDA itself labels it “Energy Bill Savings to Participating Customers,” a modeled, expected-lifetime estimate that includes projects still in the pipeline, has generally not been adjusted through evaluation, measurement, and verification, and is compared only against historical program expenditures — not against the full cost RGGI imposes on all ratepayers.

That full cost is larger than the Administration’s messaging acknowledges, because RGGI requires fossil-fueled generators to hold an allowance for every ton of CO2 emitted, and that allowance price becomes part of the generator’s bid into New York’s marginal-price wholesale electricity market. When an emitting generator sets the clearing price for an interval, its RGGI cost is embedded in the price paid to every accepted resource in that interval — not just reimbursed to the unit that bought the allowance. Non-emitting and even imported resources collect the higher clearing price while bearing little or none of the underlying RGGI cost themselves.  That markedly increases consumer costs.

When I include that market-wide effect rather than just the direct cost of allowances sold at auction, the total annual RGGI cost roughly doubles, and it is rising steeply. Between 2021 and 2024 — the most recent year with complete data — the total annual RGGI cost rose $233 million, or 37 percent. Pro-rating 2026 by the Auction 72 price of $35, the annual cost rises a further $1,317 million, more than 2.7 times the 2021 level.

For a typical residential customer using about 570 kWh a month (roughly 6.9 MWh a year), the same pattern holds at the household level. Counting only direct allowance costs, RGGI added about $24 a year in 2024; counting the full wholesale-market effect, the total was $70 — nearly triple. Between 2021 and 2024, the residential RGGI cost more than doubled. Pro-rated to the Auction 72 price, the 2026 residential cost rises to roughly $121 a year, more than 2.5 times the 2021 level and about 7 percent of a typical residential electric bill, up from 4.2 percent in 2024.

None of that disappears because the state calls the auction proceeds an “investment.” Consumers pay the higher embedded cost first, in every kilowatt-hour they buy. Only a portion of the proceeds comes back later, and only to selected programs or selected bill-credit recipients. A household that does not qualify for a program, cannot front the money for an efficiency upgrade, or does not live in a service territory where a credit applies still pays the RGGI-driven cost in full, with nothing returned.

There is also a time-value-of-money problem a colleague of mine, who prefers to remain anonymous, framed better than I have seen it framed elsewhere: RGGI takes a dollar from the consumer now and, through delayed, partially administered programs, returns a fraction of that dollar’s value later — with people who fall short of program eligibility, or who simply do not navigate the application process, absorbing the difference in full, indefinitely. Discount that delayed, diminished return to present value, and the “6-to-1” ratio looks considerably less generous than advertised. And a meaningful share of the RGGI-driven cost — the wholesale market cost adder — is never captured by any investment program at all. It simply flows through as a cost, full stop.

Why the Cap-and-Invest “unsure” number should worry the Administration

The Empire Center poll found that NYCI support is closely divided with roughly one in five voters unsure, and the unsure share approaches 30 percent in some groups. I read that as evidence that most New Yorkers have not yet connected the dots between the state’s climate programs and their own utility bills. RGGI is the perfect case study for what happens if they make that connection. It is a smaller, narrower program than the proposed economy-wide NYCI, it has been running for over 15 years, and it has already produced a documented, multiplying cost to residential ratepayers with a benefit accounting that does not hold up to scrutiny. If NYCI is layered on top of a wholesale market that already embeds a RGGI-driven price adder, the affordability math the 42-percent plurality is implicitly demanding gets harder to satisfy, not easier.

My review of NYSERDA’s reported results also raises a separate, more basic question about whether RGGI is even accomplishing its stated purpose efficiently. Using the state’s own reported cumulative annualized program benefits, I estimate a cost of approximately $583 per ton of CO2 reduced, and the RGGI investment-related savings account for only about 4.7 percent of the electric-sector emissions reductions observed since the program began. Most of the historic reduction is instead associated with fuel switching from coal and oil to lower-emitting natural gas — a transition that offers little room for further reductions going forward.  It is unlikely that RGGI proceed investment in emission reductions necessary to meet the recently approved RGGI amendments will reduce emissions enough to insure compliance.

Discussion

Put the two pieces together and the picture is straightforward. The Empire Center poll shows New Yorkers will support emissions reductions on one condition: that they not raise energy prices. RGGI, the state’s longest-running carbon-pricing program and the direct model for the emissions math the Administration cites to defend Cap-and-Invest, has raised the allowance price 276 percent since Hochul took office and now adds roughly 7 percent to a typical residential electric bill when the full wholesale-market effect is counted — a cost the Administration’s own messaging does not disclose. New Yorkers do not have detailed RGGI cost breakdowns in front of them when they answer a pollster’s question, but the plurality’s instinct — reduce emissions, but do not raise my bill — is exactly the standard RGGI is failing to meet.

Conclusion

Governor Hochul has said affordability comes first. An affordability agenda should not rest on a rising RGGI charge today, defended by a “nearly 6-to-1” ratio that is not demonstrated, realized, or verified. If the Administration wants to prove a real net benefit, it should ask NYISO to calculate the wholesale-market impact using the hourly data only NYISO has, count only realized and verified bill savings against the full cost including the market-clearing-price effect, and publish that accounting for public review. Until that happens, the polling makes plain that New Yorkers are not being given what they say they want, and the RGGI cost record makes plain why.

Hochul and RGGI Affordability

Governor Hochul has said that affordability comes first, however this post shows that her Regional Greenhouse Gas Initiative (RGGI) record says otherwise. I recently wrote about the implications of the New York approval of RGGI amendments which finalized New York’s alignment with the RGGI Third Program Review Model Rule on August 5, 2026. That post focused on the flaws in the “nearly 6-to-1” ratepayer benefit cost savings claim. This post makes a related but separate point: whatever the merits of the emissions math, the price record of the RGGI program itself is an inconvenient fact for a Governor who has made affordability her signature message. Because of the importance of consumer costs, I have updated and fully documented my consumer cost estimates.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

Background information about RGGI is available in the previous post and I have prepared a technical support document that explains the calculation methodology and provides cost background information.

The affordability claim meets reality

Governor Hochul has repeatedly told New Yorkers that affordability is her top priority. Her 2026 agenda and the May 2026 relief package were both framed explicitly as responses to high utility and gasoline costs. That framing invites a simple test: have the energy policies her Administration has advanced and defended made electricity more or less expensive?

On the RGGI allowance price alone, the answer is not close. When Hochul took office in late August 2021, the most recent completed auction — Auction 52 on June 2, 2021 — had cleared at $7.60 per ton. The first auction after she became Governor, Auction 53 in September 2021, cleared at $9.30. The most recent completed auction as of this writing, Auction 72 on June 3, 2026, cleared at $35.00 per allowance, selling all 18,349,699 allowances offered for total regional proceeds of about $642.2 million.  New York proceeds were $194.7 million on the sale of 5,563,451 allowances. At the time this was written, the secondary market for RGGI allowances is trading above $35.00 per allowance.

Measured from the first full auction of her tenure, that is an increase of $25.70 per ton, or 276% over a five-year period. The RGGI carbon price has multiplied nearly three times over on her watch, and it did so with the active participation of the state agencies she oversees — Department of Environmental Conservation (DEC), New York State Energy Research & Development Authority (NYSERDA), and the Department of Public Service (DPS), all of which take part in RGGI program design, auction administration, and the decisions that determine how aggressively the RGGI allowance cap is tightened.  There is no doubt that the recent price rise is related at least in part to the recently approved DEC amendments that mandate an arbitrary auction cap reduction consistent with state laws but are inconsistent with emission reductions that can be expected from RGGI auction revenue investments.

RGGI consumer costs

DEC and NYSERDA’s press release describing the final amendments claims RGGI investments have generated “nearly $12 billion in net ratepayer savings” against roughly $2 billion invested.  This benefit cost ratio only considers ratepayer costs of RGGI allowance auction investments. The Technical Support Document describes the source of those values, and it clearly only refers to auction revenues.

I have made this point in prior posts and it bears repeating because the Administration’s messaging has not acknowledged that there is a market clearing price effect. RGGI requires fossil-fueled generators to hold an allowance for every ton of CO2 they emit. That allowance price becomes a variable operating cost for the generator and part of their bid to market. In New York’s marginal-price wholesale electricity market, when an emitting generator sets the clearing price for an interval, its allowance cost is part of the bid and can raise the total energy price paid to every accepted resource in that interval — not merely reimburse the emitting unit for the allowances it bought. Non-emitting and even imported resources can collect the higher price despite bearing little or none of the underlying RGGI cost themselves.

Table 1 lists the total annual estimated RGGI costs. For consistency with the NYSERDA and DEC analyses I estimated annual RGGI costs through 2024, but I estimated a cost for 2026 by scaling the average auction price of allowances in 2024 by the Auction 72 $35 allowance cost. The Administration messaging only considers the cost of allowances sold in auction – the total direct RGGI allowance cost row. As described in the Technical Support Document I calculated estimates that include the variable operating costs in the wholesale electric market. When those costs are included the price impact of RGGI doubles and costs are rising steeply (Figure 1). We have complete numbers for 2024. Between 2021 when Hochul took office the annual RGGI costs have increased $233 million or 37%. Holding everything else constant but pro-rating the total by the Auction 72 $35 allowance cost the 2026 annual cost increases $1,317 million or more than 2.7 times higher.

Table 1:  Total Annual RGGI Costs($ millions)

Figure 1: Total Annual RGGI Cost Trend ($ millions)

I also estimated the annual cost to residential customers. A typical New York residential electric customer uses approximately 570 kWh per month (about 6.9 MWh annually). Table 2 lists the annual estimated RGGI costs for residential consumers. If the only costs considered are the direct cost of allowances the estimated costs are half as much as when the wholesale electric market costs are included. For example, in 2024 allowance costs were $24 a year but the total cost was $70 for the estimated mix of unit types. Between 2021 when Hochul took office and 2024 the residential annual RGGI costs have more than doubled. Holding everything else constant but pro-rating the total by the Auction 72 $35 allowance cost the annual cost increases $121 a year or more than 2.5 times higher. This represents over 7% of residential electric costs. This continues a trend (Figure 2) that I expect to continue to grow.

Table 2: Annual Residential Cost of RGGI ($)

Figure 2: Annual Residential Cost of RGGI ($) Trend

These cost estimates show the RGGI price increase does not stay contained to a line item on the emitting generator’s books. It works its way into wholesale prices, and from there into what load-serving entities — and retail customers — pay for the electric commodity they consume.

None of that disappears because the state collects auction revenue and calls the proceeds an “investment.” Consumers pay the higher embedded cost first, through what they are charged for each kilowatt of electricity. Only a portion of the allowance proceeds comes back later, to selected programs, or selected bill-credit recipients. A household that does not qualify for a program, cannot front the money for an efficiency upgrade, or simply does not live in a service territory where a credit is applied still pays the RGGI-driven cost with nothing returned.

The “6-to-1 return” does not rebut this

DEC and NYSERDA’s press release describing the final amendments claims RGGI investments have generated “nearly $12 billion in net ratepayer savings” against roughly $2 billion invested — a “nearly 6-to-1” return that supposedly proves affordability is being served. The Technical Support Document explains the source of those values. I evaluated that NYSERDA report and the qualifications matter: the $12.334 billion figure is not verified net ratepayer savings. NYSERDA itself calls it “Energy Bill Savings to Participating Customers,” a modeled, expected-lifetime estimate that includes savings from projects still in the pipeline, has generally not been adjusted through evaluation, measurement, and verification, and is compared against historical expenditures rather than against the full cost of the program to all ratepayers, including the market-clearing-price effect described above.

There is also a time-value-of-money problem that a colleague who prefers to remain anonymous framed better than I have seen it framed elsewhere: RGGI takes a dollar from the consumer now and, through delayed, partially administered programs, returns a fraction of that dollar’s value later — with the people who fall short of program eligibility or who face the ordinary friction of applying for assistance left to absorb the difference in full, indefinitely. Discount that delayed, diminished return to present value and the headline “6-to-1” ratio looks a great deal less generous than it is advertised to be. And a meaningful share of the RGGI-driven cost embedded in electricity bills — the wholesale-market cost adder described above — is never captured by any investment program at all. It simply flows through to consumers as a cost, full stop, with no delayed benefit on the other end. The exemplifies a true affordability issue for most energy consumers who are not eligible for the programs or credits created for a small percentage of energy customers.

My numbers show that when the energy costs are included the 6 to 1 benefit ratio is unsupported.

The contradiction Hochul has not had to answer

The same Administration that says it wants to protect New Yorkers from high energy costs signed off on a Third Program Review that lowers the regional RGGI cap sharply through 2037, with steeper annual reductions from 2027 through 2033. A tighter cap means a smaller supply of allowances at a time when there is growing electricity demand — precisely the dynamic that has already pushed the allowance price up 40 percent in a single quarter this year. RGGI’s own market monitor has acknowledged the resulting affordability and scarcity concerns are real, not hypothetical.

An affordability agenda should not rest on imposing a rising energy charge today while pointing to a modeled, largely unverified, multi-year savings projection as the offset. Governor Hochul cannot credibly claim affordability is her governing priority while her Administration has overseen — and just locked in further tightening of — a program whose price has risen nearly fourfold on her watch.

Discussion

In my opinion, the cost of RGGI allowances is another buried cost of the clean energy transition that very few people know about. In 2024 the impact of RGGI allowances accounted for $70 per year or 4.2% of a typical residential electric bill. Projecting the latest sharp rise in allowances raises the costs to $121 per year or 7.2% of a typical residential electric bill. At a time when there is an energy affordability crisis it is fair to ask whether New Yorkers are willing to pay for this program?

The Administration messaging about the “6-to-1” benefit to cost claim is unsupportable and self-promoting at best. If they want to prove a positive benefit/cost ratio then they should request that NYISO provide the wholesale market impact calculated with the hourly data that only they have. For the benefits they should only consider savings actually returned to consumers, broken out from savings that are committed but not yet delivering measured savings. They should also only include verified, evaluated-and-measured bill savings — not modeled lifetime projections — compared against the total full cost.

Until that accounting exists, “nearly 6-to-1” is a talking point, not a demonstrated result. New Yorkers who have watched the RGGI price climb from $9.30 to $35.00 per ton since Hochul took office are entitled to something better than the assurance that the difference will average out favorably over a very long period of time while losing the time value of the dollar spent today for energy consumed.

Conclusion

The combination of New York’s wholesale electric-market structure and the recent sharp increase in RGGI allowance prices means that the program is no longer a marginal cost with little consequence for consumers. It is now a meaningful contributor to residential electric bills.

My review of NYSERDA’s reported results indicates that RGGI-funded investments have produced relatively little measured progress toward the program’s core purpose: reducing emissions from the electric generating units subject to the RGGI cap. Using the State’s reported cumulative annualized program benefits, I estimate a cost of approximately $583 per ton of CO2 reduced. Moreover, the RGGI investment-related savings represent only about 4.7% of the electric-sector emissions reductions observed since the program began. Most of the historic reduction appears instead to be associated with fuel switching from coal and oil to lower-emitting natural gas—a transition that offers little opportunity for additional reductions going forward.

That mismatch matters because RGGI is fundamentally a power-sector compliance program, not simply a source of funding for otherwise worthwhile State initiatives. If allowance costs are adding more than 7% to residential electric bills, then New York should be able to demonstrate that the revenues are being directed first to cost-effective measures that reduce emissions from RGGI-covered sources, lower customer bills, and help maintain reliable compliance with an increasingly stringent cap.

Governor Hochul has emphasized energy affordability. That commitment should require an independent, transparent review of whether New York’s continued participation in RGGI—as presently designed and implemented—delivers emissions reductions and consumer benefits proportionate to its cost. If it does not, then withdrawal from RGGI, or at minimum a fundamental restructuring of the program and its revenue-allocation rules, should be considered a necessary test of rational energy policy.