Category: Climate Act

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.

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.

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.

New York Energy Policy BESS Disconnect

People send me things that are often topics for this blog.  When Greg Harkenrider sent an email describing the disconnect between New York energy policy “renewable” generation goals and its storage goals I asked him if I could publish it as a blog post.  It is a good independent analysis of yet another challenge of the Climate Leadership & Community Protection Act (CLCPA) transition away from fossil fuels.

Greg is a retiree from the New York state Department of Transportation and the vice president of Stop Energy Sprawl, a coalition of local groups opposing large-scale wind and solar projects.

The Problem

A principal state energy goal is a zero-emissions electric grid by 2040. This requires eliminating all fossil fuel generation, maintaining existing hydro and nuclear power, and vastly increasing wind and solar power. (Recently there has been discussion of additional nuclear generation, but for now that is just in the talking stage.)

Wind and solar have two main problems: 1) their productivity is low — solar produces on average less than 20 percent of its capacity in New York state, and wind about 25 percent; and 2) they are erratic (aka “intermittent”), varying substantially by time of year and from day to day, depending on wind speed and cloud cover.  New York’s policy has been to build its way out of problem #1 by massive deployment of wind and solar facilities and store its way out of #2 with batteries.

A critical question is the amount of storage needed to run the New York State grid by 2040 on wind, solar, batteries, no fossil fuels and no increase in hydro because there are no additional resources available for development or nuclear generation because the CLCPA authors thought it was unnecessary. This is not just a matter of powering up the batteries during the day, then using their power after sundown, important as that is. An electric grid powered substantially by wind and solar will have to rely on batteries for extended periods.

Battery Requirements

The analysis here uses a year’s worth of cloud cover and wind speed data from the National Weather Service to estimate how “substantial” and “extended” we are likely to get. I used current hydro and nuclear generation and added enough wind and solar power to match the New York Independent System Operators estimated demand for the year 2040. I created a spreadsheet where days of excess wind and solar production have energy added to storage, and days of deficit production have energy withdrawn from it.

When we examine electric generation and consumption on this day-to-day basis, the critical factor is not just the seven to ten consecutive days of cloudy skies and still winds that occur two or three times a year, but the three-month period from early November to early February, when bad days for wind and solar far outnumber the good days. Getting through this period with the wind/solar resource mix we are pursuing now would require 8,800 GWh of battery production capacity. 

To illustrate the problem, Table 1 below uses National Weather Service daily wind speed and cloud cover data for one week of December 2023, and calculates the generation that would have been provided by the predominantly wind and solar grid described above:

Table 1: Daily Generation & Battery Need for One Week in December

I deliberately picked a week that had both good and bad days for wind and solar. For the first three days, weather was good and we would have generated more electricity than we needed, enabling a fairly significant net increase in battery charging. It was followed by dense cloud cover and calm circulation that would have required about 1,000 GWh of battery discharge in just four days. And the problem does not last just four days. A wind/solar grid will face a shortfall for two to three months every year.

This table is based on weather conditions in December 2023, and generation totals would differ from one year to the next. But the variability of wind and solar production, and consequently the need for storage, would be the same.

When we do the math on a day-by-day basis, the result with this combination of generation is that batteries need to supply more than 6,000 GWh of power between early November and early February, when solar generation begins to improve. Batteries cannot be charged up to their full capacity, nor discharged to zero. Hence the need for 8,800 GWh of capacity.

November, December and January are the worst months for solar power. This critical factor is masked by annual averages. For instance, the Energy Information Administration (part of U.S. Dept. of Energy) reported the average 2024 capacity factor for solar facilities in New York at 17 percent. However the average for November to January was just 7 percent. And, as seen in the table, monthly averages mask daily variability.

The battery quantity would depend on their average duration. Those currently deployed are almost all four-hour duration. It is optimistic, but possible, that that could double to eight hours by 2040. Even if it did, we would need more than 1,000 GW of batteries. Contrast that with the Governor’s aspiration to get to six GW– less than 1 percent of need.

Considering that one 40-foot shipping container-sized battery unit has a capacity of about four megawatts, we would need 275,000 such units to provide that amount of storage (optimistically assuming eight-hour duration). Put another way, the largest battery storage in the country, the Moss Landing facility in California, has a capacity of three GWh. We would need to build 3,000 Moss Landings to back up a wind/solar grid, with only the existing amount of hydro and nuclear generation.

The assumption here is that the state’s future mix of wind and solar remains close to the three-fourths solar/one-fourth wind that is in process now. A grid of 14 GW of land-based wind, 7 GW of off-shore wind, 47 GW of solar and the current 4.3 GW of hydro and 3.3 GW of nuclear would (with Quebec Hydro imports), over the course of a year, provide enough power to meet 2040 demand, as projected by the New York Independent System Operator. But it would do so by over-producing at some times and under-producing at others.

Alternatives

This result is so implausible that we need to look at alternatives. If we shift the future wind/solar mix closer to half and half, the storage need is less — about 6,400 GWh — but still impossible. (There is about a two-month dry spell rather than three, as November is usually a good month for wind.)

Trying a third alternative, the story gets better, but not much. Assume roughly doubling nuclear capacity from the current 3,300 MW to 7,000, while still eliminating all fossil fuel generation. Under this scenario, the December-January battery need would remain, but at a smaller level — about 4,900 GWh. Wind, solar and hydro would provide about 68 percent of generation, close to the state’s policy goal.

Under any scenario, battery charging/discharging would have to be managed, not only centrally, but perfectly. Batteries would have to be discharged in succession, not at the discretion of private operators as they are now. Just getting averages to work does not get every kilowatt to exactly the right place at exactly the right instant. I cannot imagine this working anywhere other than on a spreadsheet.

Caiazza Comment:  This is an important point because experience in Australia showed that battery system applications are more complex than generally assumed.  In addition to storage backup a battery can earn revenues and justify investment by selling power capacity, speed, and availability into ancillary-service markets.  This means that more batteries will be needed because the batteries will not be dedicated to energy storage applications and they cannot service both applications.

The cost of such battery deployments would be astronomical. We cannot expect the current unit costs to prevail if we attempt to procure such a quantity. Estimates range from the hundreds of billions to more than a trillion dollars, just for New York state.

Practical Scenario

So, if the current wind/solar mix is impossible, and shifting to more wind is impossible, and supplementing 70 percent “renewable” with nuclear is impossible, we need to ask what zero emission scenario could work.

The best way to answer this is to reverse our process and start with a realistic estimate of battery deployment, then manipulate the generation sources to model a functioning 2040 grid. I used 300 GWh of storage. If average battery duration improves to eight hours by 2040, that would require 37.5 GW, about six times the current goal.

Making this work requires increasing New York’s nuclear capacity by nearly five times its current level to more than 15 GW. Wind and solar were limited to the projects currently operating or in the state’s application process — about 12.9 GW of solar and 4.5 GW of wind. Empire and Sunrise were the only new off-shore wind assumed.

The key point is that to get storage needs to a realistic level, we must curtail the amount of wind and solar generation. Put another way, renewable generation and storage must be in balance. Without fossil fuels, that can only happen at a far smaller deployment of wind and solar energy than is planned now.

With this mix, 30 percent of New York’s electricity is produced by “renewable” sources. When the landmark CLCPA was passed in 2019, 26 percent was “renewable.” The 2040 New York’s Climate Act goal is “zero emissions” so this approach is compliant.  What we do have is at least the possibility of a functioning, zero-emission electric grid, with an achievable amount of battery storage and the likelihood of being a net electricity exporter.

Is this any more realistic than the “impossible” alternatives? New York has four large nuclear plants operating now. This would require us to build 12 to 15 more of them, or a larger number of small, modular reactors. If the state reached a consensus to do that today, it would take a crash effort to get it done by 2040. Public and political opinion on nuclear power is beginning to shift, but we are far from resolved on such a change in policy. The resolute opposition to nuclear power that has prevailed among politicians, regulators and the public since the 1970s will take years, not months, to change. And even if it does change, we must remember that nuclear power has many good points, but speedy design and construction has never been one of them.

Table 2 summarizes the 2040 electricity production in GWh by generation type for the four alternatives discussed in this narrative.

Table 2: NYS Generation & Storage Needs for Zero Emissions in 2040 (GWh)

Any such analysis must pile assumptions upon assumptions. A few of mine are listed below:

  • Projected demand is from the 2026 NYISO Gold Book, which is only an educated guess. Note that the 2025 Gold Book projected 2040 demand at 201,870 GWh; the 2026 version reduced that to 183,800. The 2025 book projected winter peak would exceed summer by 2039, then the 2026 version pushed that back 10 years, to 2049. It is not only meteorologists who have difficulty forecasting.
  • Except for being unavailable in winter, Hydro Quebec imports would be available when needed.
  • Batteries can be charged up to 85 percent of capacity and discharged to no less than 15 percent.

Conclusion:

For too long, New York state has had a policy for “renewable” energy generation that conflicts with its policy for energy storage. The state’s policy makers who are on a sprint to develop wind and solar energy have no clue how much battery storage that will require, and they don’t particularly want to learn. This paper is an attempt to show that numerically.

Comments are welcome. Greg can be contacted at stopenergysprawl@gmail.com

New York State’s Short-Sighted Approval of RGGI Amendments

A couple of months ago I wrote that the Regional Greenhouse Gas Initiative (RGGI) needs to be revised. Unfortunately, the New York State Department of Environmental Conservation (DEC) approved amendments to Part 242 CO2 Budget Trading Program that is consistent with the RGGI Third Program Review but are at odds to changes since the completion of the amendment implementation process. This post explains why I think this action was short-sighted and incorrect.

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program. I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program. 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. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several 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.

Background

RGGI is a market-based program to reduce greenhouse gas emissions (GHG) (Factsheet). It has been a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector since 2008. New Jersey was in at the beginning, dropped out for years, and re-joined in 2020. Virginia joined in 2021, withdrew in 2024, and rejoined effective July 1, 2026, and Pennsylvania considered joining but has since decided not to join. RGGI includes a provision for regular reviews. The Third Program Review was completed in July 2025. It strengthened the regional CO₂ emissions cap through 2037, with steeper reductions from 2027 to 2033 and a lower rate thereafter. New York was required to align their regulations with the updated Model Rule by January 1, 2027.

It appears that DEC approved amendments that made the NY carbon trading rule consistent with the Model Rule to meet this alignment requirement. However, I believe that there were significant changes to the RGGI and New York landscape that should have been considered. As a result DEC should push for an immediate start to a Fourth Program Review.

Timeline

The public comment period for the proposed revisions to 6 NYCRR Part 242 and associated regulations began on December 10, 2025, and closed on February 17, 2026. DEC held two virtual public hearings in February 2026 to take testimony on the proposal. On June 23, 2026, the New York State Energy Research & Development Authority (NYSERDA) Board approved companion revisions to its 21 NYCRR Part 507 CO2 Allowance Auction Program regulation so that the auction rule would align with the Part 242 amendments. On August 5, 2026, DEC and NYSERDA jointly announced that they had finalized the regulations, with the amendments taking effect January 1, 2027.

In other words, over the eight months between the close of the comment period and final adoption, DEC had every opportunity to reconsider the proposal in light of events that undercut the analytical basis it had relied on. Instead, the final rule that emerged in August is, in every respect that matters, the same rule that was proposed in December – a rule based on modeling and assumptions that had already been superseded by the time it was finalized. That is my problem with this rulemaking. It is not that DEC failed to follow the Model Rule. It is that DEC treated an evolving policy and market landscape as if it did not exist.

Factors not Considered

Since the draft amendments were finalized, there have been several significant changes to the NYS regulatory landscape that DEC’s response to comments does not meaningfully grapple with.

The State Energy Plan was finalized after the close of the comment period. DEC’s responses to comments repeatedly lean on the State Energy Plan (SEP) Additional Action case as evidence that the proposed cap trajectory is “consistent” with the SEP and is “on a pathway to zero emissions by 2040.” IPPNY comments noted that the SEP’s Additional Action case assumed the Climate Act’s zero-emissions target would be reached by 2045, not 2040 – a five-year gap that DEC’s response does not reconcile, beyond restating that the cap trajectory is “on a pathway to zero emissions by 2040.” That raises an obvious problem: the SEP itself was still being finalized while this rulemaking was underway, and DEC cannot simultaneously treat the SEP as settled, authoritative support for its cap trajectory while the SEP was not yet final policy. You cannot borrow credibility from a document that was still being written.

The May 2026 budget bill changed New York’s underlying emission reduction requirements. In Part VV of the budget bill, the Legislature substantially rewrote the Climate Act’s statutory GHG accounting and planning provisions. As I described in more detail when the bill passed, the budget bill revisions to the CLCPA replaced the hard 40% by 2030 reduction requirement with a directive that DEC adopt regulations by December 31, 2028 to achieve a 60% by 2040 reduction “to the maximum extent feasible and cost effective.” That relaxes the statutory pressure to adopt an allowance allocation trajectory consistent with “zero emissions” by 2040. The Sabin Center’s white paper on the 2026 climate law changes reached a similar conclusion, describing the amendments as a retreat from the original Climate Act framework. I had made this same point in 2023 when the cap-and-invest program first showed up in a budget bill – the Legislature has repeatedly used the budget process to quietly rewrite the Climate Act’s substance rather than debate it as standalone legislation. The Part 242 amendments adopted in August, however, do not reflect any of this. DEC finalized a New York-specific allowance budget as though the emission reduction requirement that supposedly justifies it had not changed at all.

Second quarter 2026 auction prices jumped significantly, making consumer impacts a real and immediate problem, not a hypothetical one. The RGGI allowance clearing price jumped 40%, from $24.99 in the March 11, 2026 auction to $35.00 in the June 3, 2026 auction.  All the original containment reserve allowances available for 2026 had already been exhausted by the March auction. I laid out the consumer cost implications of that price jump when the results came out.  Direct allowance purchase costs to New York consumers were already running around $700 million a year at 2025 average prices, and would rise to well over $1.1 billion a year if the $35 price persists.  DEC has not acknowledged that when the wholesale electric market cost adder created by RGGI-obligated generators bidding in their allowance costs is included, the plausible statewide consumer burden runs into the $1.8 to $3.2 billion range depending on which generating technology sets the marginal price. A meaningful share of that embedded cost becomes windfall revenue for generators that have no RGGI compliance obligation of their own and never flows back to ratepayers through any investment program. None of that was reflected in the cost impact analysis DEC relied on to finalize this rule, because that analysis predates the price spike. DEC’s responses to comments statd that “the average residential, commercial, and industrial consumer of electricity is anticipated to see no significant change in their bills as a result of this rule making” – a conclusion drawn from modeling that has already been overtaken by events on the ground. (See my RGGI Quarter 2 2026 Auction Results post for the full analysis.)

Taken together, these three developments describe a rulemaking that was adopted on autopilot. The SEP that DEC cites as validation was not yet final when the comment period closed. The statutory emission reduction targets that supposedly justify the cap trajectory were rewritten by the Legislature while the rule was pending. And the auction market that DEC’s affordability conclusions depend on moved sharply against ratepayers before the ink was dry. Any one of those developments would be reason enough to pause and take another look. All three together are as close to a mandate for reconsideration as a rulemaking record is ever going to hand you, and DEC did not take it.

Bottom Line

DEC had a genuine opportunity, between the close of the comment period in February and final adoption in August, to reconsider a rule whose analytical foundation had visibly eroded out from under it. The State Energy Plan it cites as validation was not final when the rule was proposed. The statutory emission reduction requirements the cap trajectory is supposed to serve were rewritten by the Legislature in May. The auction market whose stability underpins DEC’s “no significant change in bills” conclusion jumped 40% in June. And three separate, technically sophisticated stakeholders – EEANY, IPPNY, and NYISO – laid out in detail why the cap trajectory, the reliability safeguards, and the affordability assumptions in this rule do not hold up, all before DEC finalized it anyway. DEC’s answer to all of it, in substance, is that the Cost Containment Reserve and the allowance bank will probably be enough, and that a Fourth Program Review will start by 2028. That is not a rebuttal. It is an acknowledgment, buried in the response-to-comments document, that the critics are right and the fix has been deferred to a review that has not even started yet. DEC should have paused this rulemaking and pushed for the Fourth Program Review immediately. Instead, New York is locked into a cap trajectory built on a foundation that DEC’s own record shows was already out of date the day it was adopted.

How Neighboring Electric Systems  Handled the July 2026 Heat Wave

This is the fourth post in my series on the electric system impacts of the late-June/early-July 2026 heat wave. The first two posts (here and here) covered the New York Independent System Operator (NYISO) system, and the third covered data that Rich Ellenbogen shared from his home and factory on the Con Edison system. This post looks outside New York, at how nearby regional transmission operators PJM, ISO New England, Midcontinent Independent System Operator (MISO), Ontario’s Independent Electricity System Operator (IESO), and Hydro-Québec handled the same event, with the focus on whether wind and solar were available when the grid needed them most.

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.

Overview

My first post in this series found that the heat dome that stressed New York’s grid was, for most of the event, centered close enough to New York to leave a decent pressure gradient — and therefore decent wind — over the state on most days, with June 29 the exception. A rapid-attribution analysis found that the anticyclone driving the heat wave was centered over the northeastern United States and southeastern Canada and stayed nearly stationary for about a week, with light-to-moderate winds across eastern North America.  Note, however that I completely disagree with the analysis claim that human driven climate change had a greater impact than natural variability.  The weather pattern affected operators sitting under or immediately downwind of the ridge core — PJM, MISO, and Ontario’s IESO — had significant wind shortfalls, while ISO-NE, helped by offshore wind on the maritime margin, did not. U.S. weekly electricity output for the week of June 28 – July 4, 2026 reached 100,996 GWh — the first week ever above 100,000 GWh, up 7.73% year over year. This was a continental event, and the country’s largest grid operator came closer to real trouble than New York did.

PJM: The Most Acute Stress in the Country

PJM Interconnection, serving 13 mid-Atlantic and Midwest states plus D.C., ran through the entire emergency ladder, making the New York Independent System Operator (NYISO) Energy Watch look mild. PJM issued Hot Weather Alerts starting June 29, escalated to a NERC EEA1 on July 1, then to EEA2 with a “Deploy All Resources” action at 5:36 p.m. on July 2, along with a Low Voltage Alert and Heavy Load Voltage Schedule Warning (PJM Operating Committee presentation; Sunairio). The U.S. Department of Energy issued two emergency orders under Federal Power Act section 202(c) to PJM on June 30, and a third effective July 2 that ran through July 6.

PJM served an estimated all-time peak of 168,158 MW between 5 and 6 p.m. on July 2, breaking the prior record of 165,563 MW set in August 2006. Forced generation outages ran between 18,100 and 19,400 MW on July 2–4, versus an average of only 12,800 MW on the top-10 summer peak days of the prior three years, and operating reserves collapsed from 10,996 MW on July 1 to just 5,091 MW on July 2 (PJM Inside Lines; mgrid). PJM’s Senior Manager of Dispatch put it bluntly: PJM “used every single generator available on July 2,” calling it the highest peak ever served, and adding that “our capacity position continues to be an area of concern” (PJM Inside Lines).

Wind was scarce almost exactly the way New York’s wind was scarce on June 29, except PJM never got the reprieve New York got on the other days. Independent fuel-mix analysis found that nuclear, coal, and gas together supplied 88% of PJM generation during the heat wave, while solar and wind combined were flat at just 7.5 GW, unchanged from the prior week; coal output rose 69% and gas rose 26% to cover the gap (EPRINC). The Department of Energy stated that during the 5 p.m. peak hours of July 2 and 3, 82% of available wind power failed to produce, and when the sun goes down solar goes offline (DOE, via Shore News Network) — a political characterization rather than a PJM operational metric, but consistent with the underlying meteorology and the independent fuel-mix data. Solar did perform well during daylight, reaching over 11,000 MW at the record hour (Grid Strategies), but when the sun goes down it does not help with the post-sunset net-load peak, exactly the deliverability problem PJM itself flagged.

PJM leaned hard on demand response, deploying an average of 6,113 MW on July 2 and 5,037 MW on July 3 (PJM Operating Committee presentation — essentially its entire contracted demand-response fleet and then some (Grid Flexibility case study). Imports offered little cushion: PJM was actually a small net importer at the record hour, drawing roughly 900 MW total from MISO, NYISO, LG&E, and TVA — a rounding error against a 168 GW peak (Grid Strategies). West Hub on-peak day-ahead prices averaged $479.27/MWh on July 2, the highest for any July or summer day on record (S&P Global). PJM avoided firm load shed, but a record peak, near-record outages, collapsing reserves, and near-total demand-response deployment is about as close to the edge as an operator can get without a blackout.

ISO New England: Tight, But Wind Actually Helped

ISO-NE issued a precautionary Abnormal Conditions Alert effective 5 p.m. on July 1, explicitly stating “this is not a system emergency,” and lifted it at 10 p.m. on July 3 (ISO-NE event record; ISO-NE newswire). ISO-NE warned that “there is little surplus generating capacity available to deal with unanticipated events,” and flagged that heat “affecting systems to the west and the north, including New York and Quebec” was “increasing uncertainty regarding energy imports to New England” (ISO-NE newswire) — a direct acknowledgment that its reliability depended on neighbors who were themselves under stress.

The July 2 peak of 25,351 MW was ISO-NE’s 2026 high, below the all-time summer record of 28,130 MW from August 2006, though behind-the-meter solar brought it within roughly 500 MW of that record (Central Maine / Portland Press Herald; Grid Status). Unlike PJM and MISO, ISO-NE’s wind performed well throughout: roughly 57 GWh generated, a 78% increase over 2025, never below 400 MW, and strongest during the afternoon and evening peak, driven largely by offshore wind (Grid Status). American Clean Power says offshore wind alone met almost 12% of total demand on July 2 (American Clean Power). That is geography and luck, not evidence that wind can be counted on generally because if the center of the heat dome was more to the northeast the wind would have failed.

MISO: High Load, Weak Wind, No Emergency

MISO declared no maximum generation emergency during this window; its first Energy Emergency Alerts of the summer came two weeks later, on July 15 (Grid Status), despite peaking at roughly 121–125 GW on June 30, within about 2 GW of its all-time record of 127 GW set in 2011 (Politico).

MISO’s wind was the second clear shortfall of the event. Grid Status reported that MISO wind was weak across the entire footprint and “particularly underperformed the forecast during the evening peak period” (Grid Status), which directly conflicts with a claim from American Clean Power, an industry trade group, that MISO wind delivered roughly five times more electricity than forecast at the peak hour (American Clean Power). The operational synopsis — wind underperforming forecast at the evening peak, when it matters most — deserves more weight than a trade-group framing.

MISO’s solar reached a peak of 18.6 GW on July 1, coal hit its highest output of 2026 to date, and batteries discharged only about 1 GW at peak, which Grid Status called “still well below the level required to cover the net load peak” MISO got through the event without an emergency and was even a net exporter, but did so on the back of coal and gas, not wind (Grid Strategies).

Ontario and Québec: The Same Ridge, the Same Wind Drought

Canada’s two largest eastern grid operators sat under the same stalled ridge as PJM and MISO, and Ontario’s experience is arguably the most direct confirmation of this series’ thesis. Ontario’s Independent Electricity System Operator (IESO) set its highest demand day of 2026 to that point on July 2, peaking at 24,734 MW during hour ending 18:00 (IESO Power Data) and July 1 and June 30 both landing in the 23,500–23,900 MW range (load-record compilation); Ontario natural-gas generation was tracking 7% above July 2025 levels for the broader event (Grid Status). Wind was nearly absent. A watchdog site tracking IESO’s public power-data feed reported that with Ontario demand above 18,000 MW, wind power was providing barely 300 MW province-wide, noting flatly that “wind is absent during most heat waves” (Ottawa Wind Concerns). A separate Ontario energy-policy blog found that industrial wind turbines generated just 9.9% of rated capacity on July 4 and only 7.2% on July 5 during the tail of the same ridge, while gas generation covered the gap — in the author’s words, gas “saved us from blackouts” (Parker Gallant Energy Perspectives). That is the same wind drought PJM and MISO experienced, documented independently on the other side of the border.

Storms tied to the heat wave also knocked out power to as many as 168,000 Hydro One customers in Ontario on July 1–2 (CityNews Montreal), and to as many as 140,000 Hydro-Québec customers on the night of July 2, with 30,000 to 50,000 still without electricity as of July 3 (CTV News; The Montreal Greek Times).

Québec matters here too: New York and New England leaned on Hydro-Québec’s hydro-based system as a backstop, and that backstop had complications of its own. NYISO drew a daily average of about 1,400 MW per hour from Hydro-Québec and 800 MW per hour from Ontario’s IESO on July 3, together covering 9% of NYISO’s demand (U.S. Energy Information Administration). But the new 1,250 MW Champlain Hudson Power Express tie line sat out entirely from July 1 through midday July 2 because of an outage on the Québec side of the border, reached full output only by mid-afternoon July 2, and then tripped into another unplanned outage on July 4 — right as the heat wave was peaking.  Net flows from Hydro-Québec into NYISO ended up down nearly 14 GWh compared with the June 2025 heat event, despite the new line (Grid Status). Even that hydro-heavy backstop could not fully deliver during the worst days of this event.

Comparing the Regions

  • PJM — all-time record peak (168,158 MW); NERC EEA2 and two DOE orders; wind and solar flat at 7.5 GW; reserves fell by more than half in a day.
  • ISO-NE — 2026 peak (25,351 MW), below the all-time record; precautionary alert only; wind up 78% year over year, never below 400 MW.
  • MISO — within 2 GW of its all-time record (121–125 GW); no emergency; wind underperformed forecast at the evening peak; solar and coal covered the gap.
  • IESO (Ontario) — 2026 high (24,734 MW); wind fell to a few hundred MW against 18,000+ MW of demand; gas covered the gap; storms cut power to 168,000 customers.
  • Hydro-Québec — storms cut power to 140,000 customers; the CHPE tie to NYISO sat idle for a day and a half, then tripped again July 4; net exports to NYISO fell from previous episodes.

Conclusion

The pattern across this heat wave was not that renewables failed everywhere — it is that wind availability tracked the weather system’s geography almost perfectly. New York, PJM, MISO, and Ontario all sat inside or near the ridge’s weak-gradient zone and paid for it in scarce wind; offshore New England did not.

That is exactly the concern I raised in my first post in this series: the weather conditions that produce the highest electricity demand — a stalled summer ridge trapping hot, humid air over a broad region — are frequently the same conditions that suppress wind output over that same region, and that region can be enormous. PJM’s dispatch manager said the capacity position “continues to be an area of concern” after setting an all-time peak with almost nothing from wind and solar combined. Ontario’s independent observers watched the same story play out with their own wind fleet, entirely independent of anything happening in the U.S. grids. New York avoided the worst of it this time only because the ridge sat somewhat south of the state for most of the week, and even then, the Canadian hydropower it counts on as a backstop had its own outages and tie-line failures at the worst possible moments. There is no meteorological law guaranteeing any of these systems will be so fortunate next time. A future grid that depends more heavily on wind, solar, and short-duration storage needs to be planned for exactly this kind of correlated, region-wide shortfall.  If all New York neighbors transition to similar weather-dependent electric systems then the New York system cannot count on any imported power.

Ellenbogen’s Data From the July 2026 Heat Wave

I have been documenting the electric system impacts of the late-June/early-July 2026 heat wave in a series of posts (My take and NYISO take) that relied on New York Independent System Operator (NYISO) system-wide data. This post is different. Rich Ellenbogen, an engineer who runs a factory in Westchester County that is about 1.4 miles from his home in New Rochelle, on the Con Edison system, shared measured voltage, frequency, generator, and solar array data he collected at both locations during the heat wave. His data illustrate at the distribution system level exactly the kind of electric system stress that the NYISO documents describe in the bulk-energy system.

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 used Perplexity AI to process commentary and data that Rich Ellenbogen shared with me and prepare a draft article. 

Overview

Rich Ellenbogen owns Allied Converters, a factory in Westchester County, and lives in New Rochelle, both served by Con Edison. His home and factory are instrumented with data-logging systems — in his words, computers that have recorded operating parameters about twice a minute for the past 22 years — plus a behind-the-meter solar array at each site and a backup generator at the factory. Those systems captured voltage, frequency, solar output, and generator operation throughout the heat wave, giving a distribution system view of the same stress that shows up in NYISO’s system-wide numbers.

Ellenbogen’s observations line up with what I found in my own analysis and with what NYISO reported to its Operating Committee: narrow reliability margins, unavailable generation and transmission capacity in the downstate region, and heavy reliance on demand response and imports will impact the New York electrical grid. His data add something the system-wide numbers cannot: what those stresses actually looked like at the meter, at a home and at a factory, in real time.

Voltage and Frequency at the Ellenbogen Factory

Ellenbogen described a sustained period of degraded power quality at his factory covering roughly three days. In his words:

The voltage was ‘browned out’ from about 4 AM on July 2 until 3 AM on July 4, a period of about 47 hours, and it was system wide, not isolated to New Rochelle. The fluctuations throughout the day on July 4 indicate that the system wasn’t truly stable until about 4 AM on July 5, which increases the time frame to nearly 72 hours.

Figure 1 is Ellenbogen’s graph of the voltage measured at his factory from July 1 through July 21. All three phases sag well below the normal ~120 V band for extended periods around July 2–4, with a brief excursion down toward 104–108 V on one phase before recovering. He also noted a sharp voltage dip around 5 PM on July 2 that he says “scrambled” the inverters on his backup generator, his factory solar array, and his home solar array, shutting them all down — the same behavior that produced the widespread blackout in Spain and Portugal earlier in 2025, when grid parameters pushed inverters out of their operating window and they disconnected at one time.

Figure 1: Voltage Measured at the Ellenbogen Factory, July 1–21, 2026

Source: Data provided by Rich Ellenbogen

Ellenbogen drew a pointed conclusion about battery storage from this experience, responding to a news article in which a battery-industry representative argued that current Public Service Commission rules do not reflect batteries’ ability to turn on and off at short notice when the grid needs it:

Theoretically, they can be turned on and off at will, but that assumes that you have the energy to charge them. These battery systems are all rated for four-hour storage. Peak load periods run from 4 PM until 11 PM, or about 7 hours. So what happens after 8 PM? … How is a 4 hour or even the new 8 hour battery system going to bridge a 47 hour event? After the first eight hours, they will be useless and at other times, there is sufficient generation and the batteries aren’t needed.

He also argued that trying to recharge more batteries on an already overloaded, low-voltage grid would have made conditions worse, because at lower voltage the current — and the charging losses — both increase, and that a grid heavily reliant on battery inverters could have blacked out entirely when the July 2 voltage dip pushed those inverters out of their operating range all at once.

The July 2–4 Event at the Factory

Ellenbogen also shared minute-by-minute data logged at the factory, about 1.4 miles from his house, covering the 72-hour period from July 2 through July 4. Figure 2 is his annotated graph of the three-phase voltage recorded there, with the July 2, 3, and 4 periods marked. He described it this way:

From looking at the graph, it is apparent that the system had major issues over a 51-hour period during the heat wave. From the first voltage dip at about 2 AM on July 2 until 5 AM on July 4.

Figure 2: Annotated Three-Phase Voltage at the Factory, July 2–4, 2026

Source: Data provided by Rich Ellenbogen

Figure 3 and Figure 4 are the corresponding factory frequency and solar output graphs for the same period. Ellenbogen noted that the power stayed stable enough to keep the factory’s inverters running through most of the event, and that the visible drops in solar output were due to clouds rather than any grid-side event.

Figure 3: Factory Grid Frequency, July 2–4, 2026

Source: Data provided by Rich Ellenbogen

Figure 4: Factory Solar Array Output, July 2–4, 2026

Source: Data provided by Rich Ellenbogen

The factory’s own logged data confirm the extent of the disturbance independently of Ellenbogen’s narrative. The 72-hour dataset for July 3 alone that he shared shows three-phase voltage swinging from a normal band near 118–122 V down to single digits — essentially a momentary loss of service — around 5:07 PM, with frequency simultaneously collapsing to about 47.65 Hz before recovering. The factory’s backup generator data show it running intermittently between roughly 1:11 PM and 5:11 PM that day, exactly the window when voltage and frequency were most unstable, which is consistent with the utility service becoming unreliable enough that the facility needed to generate its own power to ride through the disturbance.

Con Edison System Voltage on July 3

Figure 5 is Ellenbogen’s chart of Con Edison system voltage on July 3, again showing all three phases at his home.  Voltage drifts down through the low 110s for most of the day — already below the nominal 120 V level — before a sharp collapse toward 100 V and below in the late afternoon, followed by a spike as high as roughly 130 V on recovery. He wrote:

You can see the voltage dropping throughout the day and the voltage dip that knocked out the solar array at 4:38 PM and then the spike to 130 volts. Then the blackout at 5:07 PM.

Figure 5: Con Edison System Voltage at Ellenbogen Home, July 3, 2026

Source: Data provided by Rich Ellenbogen

Figures 6 and 7 show the corresponding frequency data for that day, first at full scale and then “magnified” to show the deviation more clearly. Ellenbogen described normal system frequency variation as a thin, fuzzy line hovering near 60 Hz, but noted a roughly 0.5 Hz swing after 4:40 PM that he called “a lot of deviation,” culminating in the reading of 47.5 Hz that marks the moment the system failed at 5:07 PM.

Figure 6: Con Edison System Frequency at Ellenbogen Home, July 3, 2026

Source: Data provided by Rich Ellenbogen

Figure 7: Con Edison System Frequency at EllenbogenHome, July 3, 2026 (Magnified)

Source: Data provided by Rich Ellenbogen

Ellenbogen connected the voltage collapse to a growing reliance on inverter-based resources — solar and batteries — that disconnect from the grid when voltage or frequency moves outside their operating range:

Compounding the issues is that the system is getting so unstable that the Behind the Meter Solar (BTM) is shutting down, as it did at my home after the large spike … As the system is becoming reliant on the output of the BTM Solar, those shutdowns further compromise the system by reducing generation. Inverters on batteries will suffer the same fate so as the system becomes more reliant on these inverter-based technologies, it’s going to become even more compromised than it is now.  The events of July 2 and 3 show how bad it has already gotten.

Home Solar Inverter Fault Log

Ellenbogen also provided the fault log from one of the inverters on his home solar array, which has more detailed logging than the older inverters at the factory. Of 353 total log entries recorded since the inverter was installed in January 2024, 54 — 15% of all entries logged over nearly 940 days of operation — occurred in just the 54-hour span between 11:26 AM on July 2 and 6:22 AM on July 4. As he put it, “the inverter was not happy.”

The fault log itself shows two distinct clusters of grid disturbances at the house. The first ran from about 11:26 AM to 1:01 PM on July 2 and logged repeated “Grid undervoltage very fast,” “Grid overvoltage fast,” and “Grid frequency disturbance” events, along with several “Phase(s) or neutral conductor not connected” faults as the inverter repeatedly disconnected and attempted to reconnect. The second cluster ran from about 4:39 PM on July 3 to 6:22 AM on July 4 — matching the timing of the voltage collapse Ellenbogen documented in Figure 5 — and shows the same pattern of undervoltage and frequency-disturbance events.  There was a “Phase(s) or neutral conductor not connected” fault sequence, and finally a “Reconnection fault grid” entry at 6:38 PM on July 3 that did not clear until 6:22 AM the next morning. Each of these events represents the inverter automatically taking the solar array offline because grid conditions had moved outside the range it is designed to tolerate — exactly the behavior Ellenbogen warned would become more disruptive as the system leans more heavily on inverter-based solar and battery resources.

Broader Consequences

Ellenbogen argued that the July 2–3 power quality problems reached well beyond his own property. He pointed to a Lohud report (also archived here) that documented a failure at the Yonkers sewage treatment plant coincident with the power issues on July 2 and 3, which released 39 million gallons of raw sewage into the Hudson River over a holiday weekend and forced cancellation of numerous river events because of the resulting pollution. He noted the irony that the state Department of Environmental Conservation (DEC) cited the plant for violating its discharge permit, while, in his view, DEC’s own permitting decisions blocking new generating capacity have contributed to the grid conditions that caused the failure in the first place. A county spokesperson quoted in the article said there had been no prior issues with the plant’s emergency generators, adding: “This situation never occurred before, but also we never had [Con Edison] dip the power like that before.”

Ellenbogen reported that the same voltage surges and dips damaged equipment at his own home — destroying surge suppressors on his battery backups, frying an elevator controller, and knocking out a communications module for his light switches, for roughly $1,450 in direct repair costs — and that neighbors in the area reported having to replace air conditioners damaged during the same period. He said that in 22 years in his home, he had never previously experienced power quality problems of this severity.

Conclusion

Rich Ellenbogen’s measured data provide ground-truth confirmation, at the level of an individual home and factory, of the system-wide stress that NYISO reported to its Operating Committee for this heat wave. Where NYISO’s presentation described unavailable generating capacity, thin operating reserves, and reliance on emergency demand response in aggregate terms, Ellenbogen’s voltage and frequency traces show what those conditions actually did to power quality on the Con Edison system: sustained under-voltage for tens of hours, a sharp voltage collapse and frequency excursion to roughly 47.5–47.65 Hz on the afternoon of July 3, and a cluster of inverter faults that took behind-the-meter solar offline at the exact moments the grid needed it most.  He also noted that his electrical systems had worked for 23 years but this heat wave caused something new on the electric system that had adverse impacts.

His central point is one I share: a fleet of four-hour or eight-hour battery systems cannot bridge a 47- to 72-hour period of degraded grid conditions, and inverter-based resources — solar and batteries alike — are prone to disconnecting from the grid precisely when voltage and frequency swing outside their normal operating range, removing generation at the worst possible time. As New York leans more heavily on these technologies to meet Climate Act mandates, this event is a warning that deserves serious engineering attention rather than the political dismissal Ellenbogen believes it has received so far.