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Climate Act Status – June 2026

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

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

Climate Act Requirements

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

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

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

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

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

Affordability: what it looks like at the household level

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

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

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

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

Reliability: weather‑dependent supply on a tight grid

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

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

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

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

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

Environmental impact and local siting

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

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

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

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

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

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

The 2026 “Reset”

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

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

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

Discussion

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

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

Conclusion

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

Hochul’s Energy Infrastructure Development Plan: Rhetoric, Not a Plan

My most recent post argued that  it is time for New York to decide what the future energy system should look like.  On September 22, 2026, Governor Hochul announced an Energy Infrastructure Development Plan (EIDP) as part of her Clean, Highly Affordable, Reliable, Grid Expansion (CHARGE) agenda. The announcement says the EIDP will provide “an actionable blueprint” for the infrastructure New York needs to meet surging electricity demand. In this post I describe what was announced and compare it to the recommendations I have made here for a reliability-first, affordability-driven approach to New York energy planning. My bottom line is that the EIDP gets the diagnosis right but, so far, it is more political rhetoric than a possible solution to the unfolding energy crisis.

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. I have followed the Climate Act since it was first proposed and have written extensively about its implementation. I have spent over 50 years in the electric generation industry analyzing the effects of air pollution control policies on operations. 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 research the material summarized in this article and prepare an initial draft.

Overview

The Climate Act established a New York “Net Zero” target (85% reduction in GHG emissions and 15% offset of emissions) by 2050. It includes a requirement that all electricity generated be “zero-emissions” by 2040. The 2022 Scoping Plan outlined how to “achieve the State’s bold clean energy and climate agenda.” Since then, the gap between the Climate Act transition and reality has become hard to ignore, and the Hochul Administration has increasingly framed its energy messaging around affordability and reliability. The EIDP is the latest example.

What was Announced

According to the Governor’s press release, the Governor is “directing the New York State Energy Planning Board to engage in comprehensive integrated planning to ensure the State has a clear and actionable perspective on the infrastructure it needs to reliably meet demand.” The release says the plan “will guide the infrastructure investment decisions by the State over the coming decades.”

The announced approach “leverages the tools available to the State including neighborhood-scale alternatives, distributed solar, and energy storage, and coordinates the development of new utility-scale clean generation and transmission.” The stated outcome is that “the EIDP will ensure the lights stay on and that progress towards a zero-emission grid continues all while controlling costs.”

The schedule is the part that caught my attention. The release states that “the EIDP process kicks off this year as part of the State Energy Plan, with an Interim Plan due in 2027 and the first comprehensive plan finalized by December 2029.” The American Public Power Association and Harris Beach Murtha summarized the announcement the same way.

The EIDP builds on the 2025 State Energy Plan that the Energy Planning Board approved on December 16, 2025. That plan provides “broad program and policy development direction” with an outlook through 2040. I see the EIDP as an attempt to add an infrastructure-specific layer to that high-level policy document. Unfortunately it still proposes no feasibility analysis.

What the EIDP Gets Right

I want to give credit where it is due. For years I have argued that New York energy planning is poorly coordinated. Climate Act targets, Scoping Plan implementation strategies, NYISO reliability analyses, utility rate cases, NYSERDA procurements, transmission proceedings, and local siting decisions all proceed on separate tracks with no one responsible for making sure the pieces fit together. The EIDP announcement acknowledges that problem.

There are four points I can support:

  • The State now accepts that load growth from manufacturing, electrification, and data centers requires a different planning response than the flat-load assumptions of the past.
  • Generation, storage, transmission, distributed resources, and demand-side alternatives are being considered together in one infrastructure discussion.
  • The announcement says grid development must address reliable service and customer costs, not just emissions targets.
  • The state needs to reconcile the work of NYISO, the Public Service Commission, NYSERDA, NYPA, and the utilities.

Those are not trivial changes. The language is closer to the premise of a pragmatic system plan than anything that came out of the Scoping Plan process or the latest Energy Plan.

Where it Falls Short

The problem is that the announcement offers words like “reliably” and “controlling costs” without any commitment to the decision rules that would make those words mean something. The following table compares the EIDP announcement to the recommendations I have made.

IssueEIDP AnnouncementMy RecommendationMy Assessment
Planning philosophyComprehensive integrated planning by the Energy Planning BoardReplace siloed, target-driven planning with one integrated plan that reconciles load, retirements, generation, transmission, siting, and costsStrong agreement in principle
ReliabilityPromises to “keep the lights on”Use NYISO and New York State Reliability Council resource adequacy standards, including multi-day wind and solar lulls in winterNo reliability standard is defined
Load growthCentral motivation for the planSeparate committed load from speculative data center announcements and make new large loads pay for their own infrastructureRight diagnosis, no cost-allocation commitment
Resource mixDistributed solar, storage, “utility-scale clean generation,” transmissionProcure enough firm, dispatchable capacity; keep existing reliable units until replacements are proven.  This includes repowering existing and building new natural gas generation.Firm capacity is not mentioned
Dispatchable emissions-free resources (DEFR)Not mentionedQuantify the need, set milestones, and identify off-ramps if the technology does not show upThe biggest gap
NuclearNot mentioned in the EIDP announcementRetain and expand nuclear as the proven zero-emissions firm resourceUnresolved
Affordability“Controlling costs”Publish full-system costs and customer bill impacts for each pathwayAn aspiration, not a test
Siting“Cut through red tape”Make land use and community impacts real planning constraintsPotential conflict
TransparencyNot addressedPublish assumptions, models, and data; provide independent reviewUnproven
ScheduleInterim plan 2027, comprehensive plan December 2029Act now on known reliability risks and economic development risks.Too slow

The DEFR Problem is Still Being Ignored

Regular readers know that I consider the dispatchable emissions-free resource (DEFR) problem to be the central risk of Climate Act implementation. The NYISO 2023-2042 System & Resource Outlook projects that “at least 20 GW of DEFR capacity would be needed by 2040 to replace the current 25.3 GW of fossil generation,” and that “upwards of 40 GW” could be required. The NYISO lists candidate technologies such as long-duration batteries, small modular nuclear reactors, hydrogen-powered generators, and fuel cells. None of them is commercially available at the scale needed today. 

The EIDP announcement does not use the term DEFR. It does not acknowledge that quantifying how much firm capacity New York will need and when it will be needed is an enormous challenge but most of all it does not recognize the Immediate need for an off ramp if it does not arrive on time or the interim need for firm, dispatchable resources that must include natural gas repowering and new builds and fuel delivery pipeline expansion to address observed problems. Any infrastructure plan that leaves those issues out is not addressing the hardest part of the problem. Wind, solar, storage, and transmission do not substitute one-for-one for dependable capacity during an extended winter cold snap with low wind and little sunlight.

Affordability Needs a Number

“Controlling costs” is not a standard anyone can check. If the Administration is serious, the EIDP should publish, for each major pathway, the capital costs, interconnection and transmission costs, backup and balancing costs, distribution upgrades, land requirements, RGGI carbon costs, and resulting customer bill impacts. It should also say how much of the cost of serving new data centers and other large loads will be paid by those customers rather than existing ratepayers. Until those numbers are on the table, affordability claims are just claims.

“Cutting Red Tape” Works Both Ways

I support faster approval of projects that are demonstrably needed. However, the “cut through red tape” language worries me. My work on utility-scale solar projects such as Horseshoe Solar shows that the permitting process is often the only place where local land-use, agricultural, and community impacts get any consideration. Streamlining without siting safeguards could simply accelerate energy sprawl. The EIDP should compare alternatives by energy density and land use, and consider rooftop and parking lot solar, brownfields, existing transmission corridors, repowering, and low-footprint firm generation.

The Schedule Does Not Match the Risk

An interim plan in 2027 and a first comprehensive plan in December 2029 provides little comfort because there are problems now. During January and February 2026, New York energy consumers were forced to bear $800/MW energy prices, Special Case Resource Winter Dispatches, and high system uplift because our aging generation portfolio was stressed. Decisions about retaining existing generation, starting natural gas and nuclear development, adding new natural gas fuel delivery capability and committing to transmission need to be made now, not 2029 if new resources are going to be in service in time to meet growing load requirements and attempt to meet the 2040 zero-emissions mandate.

What a Credible Interim EIDP Should Include

If the EIDP is going to be more than another politically-driven policy document, I believe the 2027 interim plan must include the following:

  • A reliability-first planning standard based on NYISO and New York State Reliability Council resource adequacy criteria that explicitly addresses extreme winter weather and multi-day renewable lulls.
  • Load forecasts by location and season that separate existing, committed, probable, and speculative large loads.
  • An explicit firm-capacity balance by zone and season that does not count wind and solar at nameplate capacity or assume DEFR will arrive on schedule.
  • A DEFR and nuclear strategy with a definition, capacity targets, in-service milestones, and contingency actions if the technologies do not materialize.
  • A rule that no dispatchable unit retires until its replacement is operating and has demonstrated dependable performance, not merely been contracted or permitted.
  • Recognition of the risk of the aging dispatchable units in the system and support to deploy fossil generation resources that can provide firm capacity where needed to bridge the transition until the Nuclear Backbone is deployed.
  • A full-system affordability test with published customer bill impacts and cost allocation to large loads.
  • A land-use and siting screen that compares alternatives on their environmental and community impacts.
  • Strategies must manage economic development, energy needs, and environmental mandates in unison not separate silos.
  • Transparent governance with published assumptions, models, and data, and formal opportunities for NYISO, consumer advocates, municipalities, and independent analysts to challenge the results.

The EIDP is Not Enough

I think that in addition to the EIDP the Hochul Administration must champion legislative and regulatory changes that recognize that reliability is paramount and that affordability controls the rate of spending are required. The EIDP will only be successful with changes to the current rules including revising the Climate Act 2040 zero emission requirement, changing any regulatory limits on deploying dispatchable generation such as natural gas fired units, and expanding the natural gas fuel delivery infrastructure to support them. Anything less is the default to our current death spiral that is impacting every NY consumer and making NY a hard choice for new economic opportunities.

Conclusion

Governor Hochul’s Energy Infrastructure Development Plan is a welcome acknowledgement that New York cannot meet unprecedented load growth, maintain reliable service, pursue its zero-emissions goals, and protect customers from rising costs through disconnected planning and procurement processes. The EIDP could provide the integrated framework New York needs.

But the announcement is a process commitment, not a reliability plan. Moreover, its timing and vagueness reeks of campaign politics.  Its value will depend on whether the State identifies firm-capacity requirements, evaluates nuclear and other dispatchable resources honestly, plans generation and transmission against actual rather than aspirational load forecasts, protects communities from unnecessary energy sprawl, and publishes a transparent full-system cost test. If the EIDP relies on hoped-for DEFR technologies, vague affordability claims, and renewable nameplate capacity instead of demonstrated dependable resources, it will simply repackage the existing planning deficiencies under a new name.  Done incorrectly risks continuing consumer affordability concerns, and missed “economic opportunities” especially for upstate New York.

I support the integrated-planning premise. I will be watching to see whether the interim plan becomes an engineering-based resource adequacy and affordability plan or just another document that assumes the Climate Act schedule can be met without saying how and delays reality through rhetoric vs actionable and timely steps forward.

Time to Decide What New York’s Energy Future Should Look Like

I have not updated my Reasons to Pause the Climate Act page in months. In the meantime, the evidence that the Climate Leadership & Community Protection Act (Climate Act) approach is unworkable keeps piling up and has reached the point that I think it is time to decide what New York’s energy future should look like. This post covers three overarching reasons New York should pause the net-zero transition until it decides what it wants the future energy system to look like: mineral supply constraints, the risk of depending on our neighbors when we need power most, and the lack of honest numbers about the cost of electrifying everything.

I have followed the Climate Act since it was first proposed and am convinced its implementation plan will adversely affect affordability and reliability. 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 research the material summarized in this article and prepare an initial draft.

Overview

The Climate Act implementation plan relies on wind, solar, and energy storage, plus a yet-to-be-developed category of dispatchable emissions-free resources (DEFR) to keep the lights on during extended periods of low wind and solar output. Nearly seven years after passage, the State still has not answered the fundamental question: what will the electric system look like when the transition is complete, and what will it cost?

Running Out of Easy Ore

Stu Turley at Energy News Beat recently published The World Is Running Out of Easy Ore. Stop Building Two Grids. His argument is that geology and manufacturing capacity, not political schedules, will determine how fast the energy system can change.

Turley, drawing on Peter Clack, explains that copper ore grades have fallen sharply since the early 1990s, so miners move far more rock, using more energy and water, for the same metal. At the same time, a new copper or lithium mine takes 12 to 17 years to develop, while net-zero mandates run on five-to-ten-year clocks. He cites the International Energy Agency’s 2025 outlook projecting a roughly 30 percent copper shortfall by 2035, lithium deficits in the 2030s, and rare-earth magnet processing concentrated in a single dominant supplier.

The mineral intensity of different resources matters. According to the IEA and World Nuclear Association figures he cites, coal and gas use roughly 7 to 8 tonnes of critical minerals per lifetime terawatt-hour, nuclear about 12, and solar and wind 124 to 200. An offshore wind plant can require about 13 times the minerals of a comparable gas plant. When the resource that uses the scarcest minerals is also the one that needs the most backup, transmission, and storage, costs are going to go up.

He also documents a grid hardware bottleneck: the United States makes only about a fifth of the large power transformers it needs, and lead times now run two to five years. Turley cites a 2026 National Center for Energy Analytics study of PJM that estimated a wind-solar-battery build would cost ratepayers more than $4 trillion over 20 years, about six times a gas-and-nuclear path, because it needs roughly ten times the nameplate capacity to ride through multi-day renewable droughts.

His central point is that we are paying for “two grids”: the physical grid that obeys physics and the policy grid that pays for mandates. The intermittent approach requires duplicate capacity, extra transmission copper, and storage that does not yet exist at scale. That describes the Climate Act plan, which needs wind, solar, storage, and DEFR.

His recommendations deserve emphasis because they describe a practical alternative. He proposes a priority test: firm megawatt-hours per ton of copper, nickel, and rare earths, and per dollar of full system cost, with supply chains under allied control. He recommends:

  • Restart sound nuclear units.
  • License new large reactors and small modular designs consistent with the Department of Energy’s goal of moving from about 100 GW toward 400 GW by 2050.
  • Build gas plants for the years before reactors are available, because they are the lowest-mineral, fastest dispatchable option.
  • Treat transformers, electrical steel, and high-voltage equipment as defense production and standardize designs that pays off in cost, licensing, operations and safety.
  • Let data centers connect when they bring firm power and hardware, not just a queue position.
  • Mine and refine copper, uranium, and rare earths on U.S. and allied ground, recognizing that recycling helps but cannot close a 30 percent copper gap.
  • Stop building the “second grid” of intermittent resources that require duplicate capacity.

New York’s plan does almost the opposite. It prioritizes the most mineral-intensive resources, phases out the fossil-fired generation that keeps the system reliable today, and treats DEFR as a problem to solve later rather than acknowledging that DEFR is necessary for the wind and solar system proposed.

New York Cannot Count on Its Neighbors

Meredith Angwin’s A Tale of Two Transmission Lines compares the two new high-voltage direct current lines that bring Québec hydropower to the Northeast. The New England Clean Energy Connect (NECEC) line to Maine is designed for 1,200 MW and the Champlain Hudson Power Express (CHPE) to Astoria in Queens is designed for 1,250 MW.

The NECEC is a comparatively simple overhead line. However, during a cold snap shortly after it went into service in January, Hydro-Québec stopped sending power for almost two days because it needed the electricity for its own customers. Angwin describes that as a policy decision: Québec is winter-peaking, and when it gets cold, Québec takes care of Québec first.

The CHPE is a 339-mile underground and underwater line. When Angwin wrote in late July, it had been down most of the month because of two physical failures. The Daily Gazette reported that a July 1 problem at a Canadian substation was fixed the next day, but a damaged cable splice in New York knocked the line out on July 4, during a heat wave. She notes that burying the line for aesthetic and ecological reasons made it more fragile because faults are harder to find and fix.

The line returned to service on July 25, but its performance since then reinforces her point. Modo Energy found that CHPE’s first-summer capacity factor was 13 percent, with 25 percent in August and 30 percent in September. That compares with the roughly 95 percent implied by the contract for 10.4 TWh a year. Since early August, the line has delivered power in an afternoon-to-evening block and sat at zero overnight. Modo also found that New York was a net exporter to Québec across the three Hydro-Québec ties this summer. Energy News Beat reported that at the 3 PM peak on August 26, the Hydro-Québec ties, including CHPE, delivered zero megawatts. Meanwhile, CBC reported that Hydro-Québec expects 2026 energy reserves of 86 TWh, down from 97 TWh in 2024 and below the 100 TWh it considers comfortable. Hydro-Québec says Québec’s needs remain the priority.

Her most important point is that this is ultimately a resource adequacy issue, not a transmission issue. Today, Québec has surplus power in the summer and the U.S. can help Québec in the winter. Electrifying vehicles in Québec and heating in the United States could eliminate the “extra” capacity both sides now share. In her words, “you need to produce the electricity before you can move it.”

The NYISO Summer 2026 Operating Study shows how much New York already depends on imports. NYISO concluded that the system can be operated reliably this summer, but look at the numbers. The Installed Capacity requirement was 39,315 MW, based on a 24.5 percent reserve margin. In-state generation capacity was 38,027 MW, so New York could not meet its own reserve requirement without the 3,168.5 MW of net external capacity purchases that were secured. The study assumed 6,164 MW of capacity would be unavailable because of forced outages and derates. NYISO notes that 1,225 MW of generation retired, including Gowanus, Narrows, and Danskammer, are scheduled to be retired, while only 225 MW was added. Gowanus and Narrows are treated as necessary resources under the short-term reliability process  through May 1, 2029. The study models CHPE at a maximum delivery of 1,250 MW into New York and 0 MW in the other direction. For comparison, the largest single generator contingency NYISO plans for is Nine Mile Point 2 at 1,310 MW. Losing CHPE is like losing one of the largest power plants in the state.

My concern is not that PJM or ISO-NE will necessarily be unable to export power. It is that their ability to provide dependable assistance is most questionable precisely when New York needs it most:

  • A Northeast-wide heat wave.
  • A prolonged winter cold spell.
  • Widespread generator derates or fuel constraints.
  • Transmission outages that reduce interface capability.

In each case our neighbors will face the same weather, the same fuel constraints, and their own customers first. Québec already showed us what happens during a cold snap. Retiring fossil generation while increasing reliance on imports and weather-dependent resources makes New York more exposed to exactly these correlated risks.

FERC’s current large-load proceedings make this a timely issue. As described by Sheppard, on June 18, 2026, FERC issued show-cause orders to six RTOs and ISOs, including NYISO, PJM, and ISO-NE, preliminarily finding their tariff treatment of large loads unjust and unreasonable. The orders call for improved load forecasting, large-load impact studies, and cost recovery agreements to protect other ratepayers, and each RTO had to report on the status of resource adequacy within 30 days. FERC recognizes that new large demand requires clearer planning, interconnection, and cost-allocation treatment in each region. If every neighboring RTO is scrambling to serve its own data centers, it is even less likely they will have spare capacity for New York during a regional emergency.

Show the Math

Matt Jacobson’s Before You Electrify Your State, Do the Math is about Maine, but every point applies to New York. After seven Maine winters with heat pumps, he likes them, but when it gets really cold they are expensive to run, so he switches to his oil furnace or wood stove. As he puts it, “My house has choices.”

Jacobson walks through the arithmetic. Central Maine Power customers pay about 25 cents per kWh. A fully electrified home using 15,000 to 20,000 kWh a year would pay roughly $3,700 to $4,900 a year for electricity. If rates stay the same and usage doubles, the bill roughly doubles, but rates will not stay the same because the system has to be bigger to generate and deliver more power. Remote wind and solar need a “very expensive extension cord,” and neighborhoods need bigger substations and lines.

He also notes that Maine’s Net Energy Billing solar program cost about $313 million in 2025, and that subsidies create a “reverse Robin Hood” effect where those who can afford solar lower their bills while renters and struggling families help pay for it. “A subsidy doesn’t reduce the cost. It changes who pays it.”

His conclusion is that before Maine makes the electrification decision for someone else, “it should have to show us its math.” New York should do the same. After nearly seven years, there still is no clear, transparent, and well-documented description of the costs, emission reductions, and realistic schedules for the Climate Act strategies.

Discussion

These topics reinforce each other. Mineral constraints mean the resources the Climate Act depends on will be more expensive and slower to deploy than planned. Import dependence means New York cannot assume its neighbors will fill the gaps when wind and solar fall short. Electrification will increase demand in summer and winter, when the system is already stressed, and the State has never shown ratepayers what it will all cost.

New York already has a mechanism to address this. Public Service Law § 66-p(4) allows the Public Service Commission to temporarily suspend or modify renewable energy program obligations if the program impedes safe and adequate electric service or causes a significant increase in arrears or disconnections. At the end of April 2026, the Commission ended a comment period regarding these safety valve provisions.  The Commission has not responded to the comments received or defined how those conditions would be tested, so there is no meaningful safety valve.

Conclusion

The Climate Act approach depends on the most mineral-intensive resources that will get more expensive as. minerals get harder to find, imports that are least dependable when we need them most, and electrification without disclosed costs. In addition, there is no deployment plan for DEFR needed to implement a renewable-dependent system.  New York needs to pause implementation and decide what it wants its future energy system to look like. That decision should be based on a priority test like the one Turley proposes: firm, reliable power per dollar of total system cost. It should include a realistic assessment of how much New York can count on its neighbors. And, as Jacobson says, the State should have to show us its math before making the decision for everyone else.

Horseshoe Solar – Unacceptable Solar Project Impacts

On September 29, 2026, the New York State Senate Minority Conference’s Energy Roundtable focused on Solar, Wind and ORES was held at the Onondaga Town Hall. One of the speakers, Janet Glocker, talked about the Horseshoe Solar project and graciously agreed to share her presentation with me. Horseshoe Solar is another example of a project that I think has unacceptable environmental impacts.

I am convinced that implementation of the Climate Act net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks coupled with the cumulative environmental impacts of those resources. These comments are based on those concerns. 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 numbers, calculations, and sources behind this post are documented in a Supporting Details attachment.

Horseshoe Solar

Horseshoe Solar was originally proposed under Article 10, so documents are available in the Article 10 permit docket. When the Office of Renewable Energy Siting (ORES) option became available, Invenergy switched, so additional documents are in the ORES permit docket.

According to Invenergy, the Horseshoe Solar Energy Center (accessed on 9/30/2026) is “a proposed 180-megawatt solar power generation facility in Livingston and Monroe Counties” that will deliver “reliable, affordable energy.” Of course, the developer’s description is optimistic. The Public Involvement Program plan claims that the project will produce enough electricity for 50,000 New York households. That is an annual-energy comparison, not a claim that the facility can power 50,000 homes around the clock. It also assumes a 23.4% capacity factor, which is higher than the 18%–19% NYISO reported for New York’s solar fleet in 2024 and 2025. At those observed rates, the household equivalent drops to about 39,000–42,000, and none of those homes would be served at night.

To its credit, Horseshoe Solar has made a permit-backed commitment to agricultural co-use, principally sheep grazing. I believe agrivoltaics commitments like this are appropriate, but I am not sure this one will ever come true. New York has about 83,000 sheep, and grazing every solar project in the interconnection queue would need about 127,000. The 2050 buildout would need about 1 million.

Janet Glocker’s Presentation

Janet Glocker lives in the Town of Rush, where part of Horseshoe Solar is being built. Her full presentation is worth reading. Her refrain throughout was “All this for less than 2 MW?” I expand on five of her points below.

Prime Farmland Conversion

Glocker described her town:

We are primarily rural and agricultural- 19,600 acres of which 50% is farmed. Soils in Rush are characterized as 60% prime farmland, 7.8% prime if drained, 12.5% soils of statewide importance; only 19.6% is not prime farmland.

The Department of Agriculture and Markets has had a goal for solar projects: limit the conversion of agricultural areas within the Project Area to no more than 10% of the soils it classifies as prime farmland that has never been made a requirement. The Department described this goal in testimony in the Trelina Solar case. Horseshoe Solar does not meet that goal. The project area is 3,748 acres, and 552 acres of prime farmland, or about 15%, will be converted to industrial solar use. To be fair, the developer removed arrays from some prime farmland during permitting. Even so, ORES approved a project that exceeds the State’s own agricultural guideline by half. My Solar Development Prime Farmland Scorecard found that most approved projects exceed it. That is a cumulative impact the Climate Act implementation process ignores.

The Genesee River Crossing

The second point is that the project is on both sides of the Genesee River, and the risks of the river crossing exceed the value of the added solar capacity. Glocker explains:

Horseshoe plans to build 8.4MW (name plate) in Rush. We all know that with Great Lakes cloud coverage and the earth’s curvature, we’re lucky if 20%, or 1.68 MW will be produced. Please remember this number- less than 2MW!

Glocker mixes capacity and energy here. Nameplate capacity is the panels’ maximum output under ideal conditions. Her 1.68 MW is the average output over a year, which is really a measure of energy. Using the capacity factors discussed above, the Rush panels would average 1.5 to 2.0 MW, so “less than 2 MW” is a fair description.

For reliability, what matters is effective capacity: how much the resource can be counted on when the system needs it. NYISO’s capacity accreditation factors credit upstate solar at only 13.85% to 15.33% of nameplate. By that measure, the Rush panels are worth about 1.2 to 1.3 MW of reliable capacity, and the entire 180 MW project is worth about 25 to 28 MW. Glocker’s “less than 2 MW” actually overstates the reliability value.

Glocker goes on:

During the Article 10 process… engineers from DPS warned Invenergy about horizontal directional drilling, karst soil, the “swiss cheese, limestone material” that underlies much of Rush. We use springs and wells in the part of Rush near Horseshoe…

The plan was to drill 7 holes under the Genesee. After hitting an aquifer in early February and having holes fill with water, new holes had to be drilled- a 42.8% failure rate. Six residences, immediately across the river from the drilling site had their springs and well water affected…

Six homes, damaged springs and wells, water totes still visible. Not knowing what is happening underground, now or in the future, would you buy one of these houses? All this for less than 2MW.

The record supports her account. 13WHAM reported that groundwater began surfacing on February 3, 2026 at 50 to 100 gallons per minute. The company told News10NBC that five homes had low water levels and that it supplied drinking water. The seepage required two rounds of chemical grouting. On August 26, 2026, ORES asked Invenergy for a plan to monitor the bore area for at least 12 more months. Nearly eight months after the aquifer was punctured, nobody can say for sure that the problem is fixed.

In fairness, the crossing is not just for the Rush panels. According to ORES, the project connects to the grid at National Grid’s Golah Substation in Rush, so power from the Caledonia arrays must also cross the river. Nonetheless, Glocker’s point stands. Rush residents bear the risks of the crossing, but their town hosts panels that are credited with only about 1.2 MW of reliable capacity. That is not a reasonable trade-off for people who depend on springs and wells.

Subsidies and Local Costs

The third point compares the subsidies from COMIDA, the Monroe County Industrial Development Agency, to the supposed benefits. Glocker explains:

IDAs are supposed to grant subsidies to promote job creation. Monroe County’s IDA, COMIDA, gave Invenergy $19 million in subsidies. In the COMIDA application, Invenergy wrote “Large scale renewable energy systems are not financially viable absent financial assistance from IDAs…”

I checked her number. The COMIDA application lists a “Total value of incentives” of $19,354,096 for the Monroe County portion of the project. However, the cost-benefit analysis in the same application puts the total cost of the exemptions at $4.9 million. The difference comes from two very different sales tax figures that I cannot reconcile. Either way, the economic benefits are small. The Horseshoe Solar website claims only $3 million in total economic investment, 300+ construction jobs, and 3 full-time jobs for the entire project. That works out to between $1.6 million and $6.5 million in tax breaks for each permanent job. The point is clear: large subsidies and little economic gain.

Glocker went on to explain that because Invenergy pays less, her county, school, and town taxes may go up. Over the 25-year payment-in-lieu-of-taxes agreement, Horseshoe will pay about $471,000 instead of $3.8 million in full taxes. Local taxes are set by budgets, so the abatement does not automatically raise anyone’s bill. However, it does mean that the new industrial facility will not carry its full share of local costs, and residents carry that burden instead. Residents also pay some of the highest electricity prices in the country. The Empire Center found that New York’s residential price was 29.93 cents per kilowatt-hour in May 2026, third highest in the nation.

Archaeological Impacts

The fourth point is archaeological impacts. Glocker states:

Honeoye Creek intersects the Genesee River at a place called Golah. The State Office of Historical Preservation (SHPO) identified the rich, alluvial soils along the Genesee and particularly at Golah as one of western NY’s most culturally rich areas. It is quite simply sacred land.

Indeed, a bone found there in 2020 during the archaeological evaluation was described by Seneca experts as human; Invenergy’s expert identified it as either a bear or a heron bone… Thousands of steel beams will be pounded into the ground to support the solar panels- what will they destroy?

The sensitivity of this area is not in dispute. A bone analysis report filed in the docket concluded that the bone was a human foot bone from an adult, not a heron or bear bone. The Seneca Nation was cited as identifying 46 known archaeological sites within 500 feet of the project and asked for further investigation using ground penetrating radar. Instead, ORES required a plan to monitor construction and deal with unanticipated discoveries. In other words, the plan is to find out whether there are graves when the construction crews hit them. I agree with Glocker that this is not an acceptable way to treat land the Seneca consider sacred.

Different Rules for Utilities and Developers

The fifth point is the difference in requirements for the utility, Niagara Mohawk Power Corporation d/b/a National Grid, and the developer. Glocker explains:

A new substation is potentially to be built at Golah by Niagara Mohawk. But utilities must undergo careful cultural investigations…

We do this for substations, but not for solar panels? All this for less than 2MW?

National Grid’s Article VII case includes a New Golah Substation in Rush. I could not find the specific Staff request Glocker quoted, but the record shows the difference she describes. National Grid’s project has gone through four phases of archaeological work, including a Phase III Data Recovery Work Plan. That plan was required after SHPO found an Indigenous site eligible for the State and National Registers. The Horseshoe arrays on the same culturally sensitive land were approved after only the first two phases. If utilities must do this for a substation, why don’t solar developers have to do it for roughly 1,260 acres of panels?

Conclusion

I think Horseshoe Solar is another solar project with unacceptable impacts. It converts more prime farmland than the State’s agricultural goal allows. The river crossing punctured an aquifer and left Rush residents on delivered water. The local subsidies are large relative to three permanent jobs. The project was permitted on land the Seneca consider sacred without the archaeological investigation required of the utility next door. All of this is for panels in Rush that NYISO credits with only about 1.2 MW of reliable capacity.

The Horseshoe Solar story is a microcosm of what is wrong with Climate Act implementation. The State is so focused on meeting arbitrary targets that it does not consider the cumulative environmental impacts on host communities. Until the State develops responsible siting requirements that protect prime farmland, water supplies, and cultural resources, I expect we will hear more stories like the one Janet Glocker told at the roundtable.

Thanks again to Janet for sending me her notes.

Independent Intervenors Tell NYPA: Reliability Must Come First in New York’s Clean-Energy Transition

On September 2, 2026, the five Independent Intervenors—Roger Caiazza, Morris Cox, Richard Ellenbogen, Francis Menton, and Constantine Kontogiannis—participated in the New York Power Authority’s annual Climate Leadership and Community Protection Act (“CLCPA”) conferral process.

New York Power Authority’s (NYPA’s) conferral process is intended to collect information and stakeholder views on the State’s progress toward CLCPA goals and to help inform NYPA’s renewable-development strategies. The Independent Intervenors’ presentation was titled “Reliability-first implementation of New York’s clean-energy transition.” Our message was straightforward: New York should not retire dependable electricity resources or assume that future technologies will solve known reliability problems before replacements are actually available, deliverable, and proven under stressed system conditions.

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

This is the first in a series of posts describing our NYPA presentation. This overview summarizes the central message and major issues raised at the conferral session. Subsequent posts will examine the supporting evidence and specific policy questions in greater detail.

The reliability-first message

The CLCPA requires New York to obtain 70 percent of its electricity from renewable resources by 2030 and to move to a zero-emissions electric system by 2040. Those goals are being pursued while electric demand is expected to increase because of building and transportation electrification, economic development, and other new loads.

The issue is not whether New York should reduce emissions. The issue is whether the State has developed a credible plan to do so without compromising reliable and affordable electricity service.

At present, the State’s energy strategy relies heavily on weather-dependent wind and solar generation, battery energy storage systems, 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.

The basic principle presented to NYPA was therefore simple:

Dependable generation should remain available until replacement resources, transmission facilities, fuel arrangements, operating reserves, and distribution-system upgrades are physically in service, deliverable to load, and proven under stressed operating conditions.

This is not a rejection of nuclear power, hydropower, transmission improvements, or renewable development. It is an argument that those resources must be evaluated according to whether they can provide the electric system services that New Yorkers need.  This need is especially acute during the difficult hours and days when demand is high, weather-dependent generation is low, equipment fails, or imports are limited.

New York has two different grid challenges

Much of the State’s energy-policy discussion focuses on the New York Independent System Operator NYISO’s “Tale of Two Grids”: the difference between upstate and downstate system conditions. That distinction is important. Upstate New York generally has more existing generation and opportunities for renewable development, while the downstate area has large load centers, constrained transmission interfaces, and special locational reliability requirements.

However, our presentation emphasized a second distinction that deserves much more attention: the difference between the bulk-power system and the distribution system.

The bulk-power system includes generation, high-voltage transmission, resource adequacy, operating reserves, imports, fuel availability, system frequency, and NYISO’s responsibility for operating the grid. A bulk-system reliability issue asks whether sufficient dependable resources are available and deliverable to load, including after credible equipment outages and during adverse weather.

The distribution system includes the substations, transformers, feeders, local circuits, voltage equipment, and utility infrastructure that physically deliver electricity to homes, businesses, hospitals, elevators, water and wastewater facilities, and other customers. The question of distribution-system resilience is whether local facilities can accommodate growing loads without compromising delivered electric quality (e.g. voltage) or service reliability.

These are related but separate challenges. A NYISO conclusion that New York has adequate statewide generating capacity does not mean that a particular substation, feeder, or transformer bank can serve growing local electric-heating and electric-vehicle load. Conversely, a local outage or voltage-quality problem should not automatically be attributed to NYISO bulk-system operations.

New York needs transparent accountability. NYISO, the Public Service Commission (PSC), NYPA, transmission owners, distribution utilities, local governments, and State agencies all have roles. The public should be able to determine which entity is responsible for identifying, planning for, funding, and correcting a particular reliability deficiency.

“The Grid Is Already Broken”

A central part of our presentation was the argument that recent events should be treated as warning signs. The grid does not have to experience a statewide blackout before reliability problems are real. Voltage reductions, localized brownouts, unstable frequency, equipment overheating, impaired restoration, and local system failures can cause significant damage and disruption.

The presentation referenced reported distribution-level problems during the June 2025 period and voltage and frequency concerns during the July 2026 heat wave. The purpose was not to claim that every incident has the same cause, or to assign responsibility before complete factual investigation. It was to explain why actual system performance should inform energy policy.

Figure 1: July 1 – July 7, 2026 Voltage Measured at the Ellenbogen Factory Showing Con Edison Voltage Instability

Source: Data provided by Rich Ellenbogen

The July 2026 experience is particularly important because modern electricity use differs from the system conditions of previous decades. Much of today’s equipment contains power electronics, electronic controls, variable-frequency drives, LED lighting, elevator-control systems, and other loads that can respond poorly to abnormal voltage conditions. In some cases, constant-power devices draw greater current as voltage falls, which can add stress to already overloaded distribution equipment.

Similarly, solar inverters, battery inverters, and generator transfer equipment cannot be assumed to provide the same support during abnormal voltage or frequency conditions that they provide during routine grid operation. These are engineering and operational questions that require transparent investigation, not assumptions based solely on nameplate capacity or annual energy estimates.

The presentation also discussed information from the late-June and early-July 2026 heat-wave period. At peak load, imports reportedly supplied roughly 10 percent of actual generation; fossil generation averaged approximately 59 percent; and wind generation ranged from roughly 1 percent to 4.6 percent. Solar-generation information should be examined with the relevant NYISO operational data when it is available.

A future post will examine these events and what can and cannot be concluded from them. The central point for this overview is that New York’s energy policy should be based on evidence from the conditions that challenge the system—not just average annual performance.

The unresolved DEFR question

New York’s planning framework assumes that a large quantity of dispatchable emission-free capacity will be necessary as fossil generation retires and electrification increases demand. Our presentation argued that this may be the most important unanswered question in CLCPA implementation.

The presentation cited a potential need for more than 10 GW of yet-to-be-identified DEFR capacity within the next several years. If that scale of dependable capacity is necessary, State policymakers and NYPA 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 State should not presume that a future technology will be available simply because planners have assigned it a useful name. Before existing dependable resources are retired, replacements should be specific, operational, and stress-tested.

This does not mean that every current fossil facility should operate indefinitely. Some older units may be inefficient, costly, or environmentally undesirable. But the correct question is whether a unit’s capacity, locational value, voltage support, fuel flexibility, and restoration contribution can be replaced by resources that are actually in service and deliverable to customers.

Wind, solar, batteries, and difficult weather

Wind, solar, and battery energy storage all have valuable roles. They can reduce fuel use and emissions, provide energy when available, assist with balancing, offer rapid response, and—in suitable locations—improve local reliability.

But a resource that is useful is not necessarily a substitute for multi-day firm capacity.

The presentation highlighted the importance of planning for weather conditions sometimes described as “dark doldrums”: prolonged periods with low wind generation, limited solar generation, and high or rising demand. These periods can be particularly difficult when combined with equipment outages, limited imports, and fuel constraints.

The July 1, 2026 example cited in the presentation showed wind generation below two percent of nameplate capability should have referred to June 29 (Table 1). It is important to note that even though July 1 wind resources were better the average generation was only 1,000 MW which represents 35% of the total NYS wind capacity of 2,858 MW. The presentation also raised concerns about smoke haze reducing solar production and referred to a January 2026 low-renewable-output period associated with critical grid risks and high consumer energy costs.

Table 1: Hourly Data for June 29, 2026

The presentation used an illustrative worst-case planning scenario involving more than 110 continuous hours with combined wind and solar output below 25 percent of nameplate capacity. The exact duration and assumptions must be documented and evaluated carefully, but the broader reliability point is indisputable: New York must be able to serve demand during prolonged periods when weather-dependent generation is unavailable.

A four-hour battery cannot provide 72 hours of firm electricity. An eight-hour battery cannot carry the grid through a 110-hour shortage. A storage plan must address not only discharge capacity but also the energy required to recharge batteries, the generation needed for charging, transmission capability, degradation, replacement costs, backup resources, and the ability to restore the batteries after a prolonged system event.

Nuclear and the transition gap

The Independent Intervenors support the State’s renewed attention to nuclear generation. Nuclear energy is a proven zero-emission source of large-scale, dependable electricity. It is not dependent on daily wind conditions or solar irradiance, and it can contribute to the long-term energy needs associated with electrification and economic growth.

However, nuclear development takes time. The presentation noted that new large-scale nuclear generation may not be available for 15 to 20 years and that the proposed 5 GW nuclear increase could be largely offset by expected resource retirements and load growth during the same period.

New nuclear generation should therefore be treated as a necessary long-term element of New York’s resource strategy, not as a near-term solution to the immediate DEFR and resource-adequacy challenge. Small modular reactors and other advanced designs should be researched and demonstrated, but should not be counted as commercially available capacity until their licensing, supply-chain, financing, construction, and operational challenges are resolved.

The State must answer a practical interim question: how will it maintain reliable service between now and the time that substantial new nuclear capacity can realistically enter service?

A constructive role for NYPA

NYPA should help answer that question. Its role should not be limited to supporting renewable projects in isolation. NYPA has financing capability, development experience, familiarity with complex infrastructure, and a public-interest mission that can be used to advance reliability as well as emissions reductions.

The presentation identified several areas for NYPA consideration:

  • Retaining and repowering needed downstate dispatchable generation, including evaluation of modern CCGT opportunities at Newburgh, Island Park, Northport, Port Jefferson, and East River locations.
  • Supporting long-term nuclear development with realistic schedules and procurement practices suited to major infrastructure projects.
  • Evaluating floating solar at Schoharie and Upper Blenheim-Gilboa reservoirs in coordination with the existing pumped-storage facility.
  • Improving the Central East interface with the CHPE converter station at New Scotland.
  • Evaluating transmission development using existing transportation corridors where practical, including an NYS Thruway route from Leeds to Dunwoodie and a possible Athens-to-Buchanan path.
  • Identifying additional hydroelectric and pumped-storage opportunities.
  • Supporting a reliability-focused planning process involving NYPA, NYISO, NYSRC, the PSC, utilities, local governments, and affected stakeholders.

Every option should be assessed transparently. The relevant questions are not simply whether a project is renewable, zero-emission, or consistent with a target. The questions are whether it is reliable, affordable, feasible to build, environmentally defensible on a lifecycle basis, and acceptable to affected communities.

Conclusion

New York needs a transition strategy based on engineering reality, transparent costs, demonstrated technology, and accountability for reliability. The State can reduce emissions, but it cannot do so responsibly by assuming away the resources and infrastructure necessary to keep electricity dependable.  That is the central message we brought to NYPA: reliability must be the binding constraint on CLCPA implementation.

Explaining the Grid Does Not Acknowledge the Need for DEFR

Matt Estes’s recent Explaining the Grid Substack post, “Wind and Solar will always, without exception fail us when we need electricity the most,” correctly objects to an overly broad claim about renewable generation. Existing wind and solar facilities plainly do produce useful energy and can reduce fuel use, emissions, and—at some times—system stress.  But the post misses the central reliability problem facing a future grid designed around weather-dependent generation: wind and solar do not have to fail all the time to create an unacceptable reliability risk. They need only fail together, for long enough, during a severe system peak to exhaust energy storage and overwhelm the remaining dispatchable resources.

For New York, that is not an abstract issue. It is the fundamental unresolved flaw in the Climate Leadership & Community Protection Act (Climate Act) transition strategy and in plans that presume wind, solar, storage, transmission, and some undefined category of “dispatchable emissions-free resources” (DEFR) can replace the dependable capacity now provided by fossil generation.

The more accurate warning is not that wind and solar “will always, without exception fail us when we need electricity the most.” It is this:

  • Wind and solar will eventually fail catastrophically during a prolonged period when electricity is needed most unless the grid has enough dependable, fuel-secure, dispatchable capacity to carry the system through the event.

That distinction matters. It explains why simply pointing out that solar and wind help during many peak-demand hours does not answer the reliability question.

I am convinced that implementation of the Climate Act net-zero mandates will do more harm than good if the future electric system relies only on wind, solar, and energy storage because of reliability and affordability risks coupled with cumulative environmental impacts of those resources. These comments are based on those concerns.  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 Estes Gets Right

Estes responds to David Blackmon’s reference to Winter Storm Uri in Texas by noting that the 2021 Texas disaster was not exclusively a wind-and-solar failure. The University of Texas assessment found that all major types of generation experienced outages or reductions during the event. In particular, roughly 25,000 MW of natural-gas capacity went offline when Texas most needed it.

That is an important point. Fossil-fueled generation is not automatically reliable merely because it is dispatchable. Generators can fail because of inadequate winterization, fuel-supply interruptions, frozen equipment, maintenance failures, transmission constraints, or poor market incentives. Texas’s failure to require adequate cold-weather preparation was a preventable institutional and engineering failure.

But that lesson does not mean weather-dependent generation has no unique reliability limitation. A gas turbine that fails because its fuel supply froze, its equipment was not winterized, or its operator did not prepare for foreseeable weather conditions has options to be made more reliable. The remedial actions are well understood:

  • Winterize equipment and gas infrastructure.
  • Firm up fuel supplies and delivery arrangements.
  • Test cold-weather performance.
  • Establish reliability standards.
  • Pay generators for availability during extreme conditions.
  • Retain sufficient reserve capacity.

Those measures may be costly, but they are technically straightforward. They address a failure of equipment, fuel delivery, regulation, or market design.

The problem with wind and solar is different. Their low-output periods are not primarily a maintenance or regulatory problem. They are an inherent feature of the underlying resource.

No amount of winterization can make the sun shine at night, increase winter solar irradiance, remove snow from every panel during a regional snow event, or make the wind blow during a persistent high-pressure system. Wind and solar output can be improved at the margin by better siting, diversity, transmission, maintenance, forecasting, and geographic dispersion, but there are inherent limitations to those resources in New Yok.  Moreover, none of those measures eliminates the possibility of an extended period of low wind and low solar output across a broad region.

That is why the appropriate question is not whether renewables ever provide useful electricity. Of course they do. The question is whether a system that relies on them can remain reliable during the rare but consequential weather conditions when their output is low for days or weeks.

The New York Reliability Problem

The Climate Act requires a transition to an economy increasingly dependent on electricity. Building heating, transportation, industrial processes, and other end uses are supposed to shift away from direct combustion of fossil fuels. As a result, New York’s electric system will have to serve a much larger share of total energy demand.

That transition changes the reliability stakes.

Today, New York’s most serious system challenges often occur during hot summer afternoons, when air-conditioning demand is high. Solar generation can be useful during those periods because its output tends to coincide with daytime cooling demand. Estes is correct that solar output can be particularly valuable during sunny summer conditions when electricity use is elevated.

However, the Climate Act’s all-electric end-state changes the planning problem. Widespread electrification of heating means that the most consequential peak-demand events are likely to occur during severe winter cold spells, particularly in the early morning and evening hours.

Those are precisely the periods when solar output is weakest or nonexistent.

New York’s winter solar resource is limited by several factors:

  • Winter days are shorter than summer days.
  • The sun is lower in the sky.
  • Peak heating demand often occurs before sunrise and after sunset.
  • Cloud cover can materially reduce output especially downwind of the Great Lakes in NY.
  • Snow cover can reduce photovoltaic production sharply or reduce it nearly to zero until panels are cleared or conditions change.
  • The coldest weather often occurs during high-pressure systems that can also suppress wind generation over broad areas.

Earlier this year I documented the impact of these factors on wind and solar availability in New York during an extended cold snap (here, here, and here).

The geography matters. New York is not Texas, California, Arizona, or Florida. General claims about solar output during hot summer days cannot be transferred automatically to an upstate New York winter reliability analysis.

Nor is it enough to say that wind output is variable but geographically diverse. There are documented weather patterns in which low wind generation extends across large areas for prolonged periods and New York wind resources are highly correlated. New York’s reliability concern is not a short-lived dip in renewable output that can be covered by a few hours of battery discharge. The concern is a multi-day—or potentially longer—period of low wind and solar generation coinciding with high electric demand.

The relevant reliability question is  therefore:

  • Can New York supply demand throughout the worst plausible extended wind-and-solar drought?  If the answer depends on unspecified future resources, then the Climate Act transition plan has not yet demonstrated that it can meet its statutory reliability obligation.

Storage Does Not Eliminate the Problem

Battery storage is valuable. It can shift solar output from midday to evening, provide frequency support, reduce ramping requirements, respond quickly to contingencies, and help cover short-duration capacity needs.

But batteries are energy-limited resources. They can discharge only until their stored energy is exhausted.

A 1,000 MW battery with four hours of duration can provide approximately 4,000 MWh of energy. That may be highly useful for managing a four-hour evening peak. It cannot, by itself, supply 1,000 MW for several days of low renewable output.

The distinction between power and energy is critical:

  • Power capacity determines how much electricity can be delivered at one time, measured in MW.
  • Energy capacity determines how long that delivery can continue, measured in MWh or GWh.

New York’s future resource planning must address both.

Short-duration batteries may help meet a resource adequacy metric based on a few peak hours. They do not necessarily solve the problem of surviving an extended period when wind and solar output remain low, demand remains elevated, and batteries cannot be fully recharged.

A grid reliant on wind, solar, and batteries has a circular vulnerability during a renewable drought:

  • Wind and solar output falls.
  • Storage discharges to meet demand.
  • Low renewable output prevents storage from recharging adequately.
  • The renewable lull continues.
  • Storage is depleted.
  • The system must depend on dispatchable generation, imports, demand reductions, or outages.

The Unanswered DEFR Question

New York energy-planning documents frequently refer to “dispatchable emissions-free resources,” but that label is not a resource plan. It is a placeholder.  A credible reliability strategy must specify:

  • What the DEFR technologies are.
  • How much capacity will be needed.
  • How much energy they can provide.
  • How long they can operate continuously.
  • What fuel or energy source they will use.
  • Whether that fuel can be stored on site or delivered reliably during extreme weather.
  • Whether the technology can be deployed at scale in New York.
  • What it will cost to build, maintain, and use.
  • Who will pay for capacity that may run very infrequently.
  • Whether the resource remains available during the same weather conditions that reduce wind and solar output.

The last point is especially important.

If New York’s DEFR solution is hydrogen manufactured with surplus wind and solar power, then the state still must demonstrate that it can produce, store, transport, and retain enough hydrogen to carry the system through the worst relevant wind-and-solar drought. Calling hydrogen “dispatchable” does not make the upstream energy problem disappear.

The system must have enough renewable energy and electrolyzer capacity to make hydrogen during favorable conditions, enough storage to preserve it until an extreme event occurs, enough generating capacity to convert the hydrogen back into electricity, and enough infrastructure to ensure that the fuel is available when needed.

That could mean maintaining a very large and very costly resource that operates only during rare events.

There is also a difficult economic problem. Suppose the weather event that establishes the planning requirement has a return period longer than the useful economic life of the DEFR facility. A resource built specifically to protect against an event expected only once every several decades may reach the end of its life before it is ever called upon to perform its defining function.  The resource still must be financed, maintained, inspected, fueled, staffed, and tested. 

That raises the unavoidable affordability question:

  • How can New York finance dependable capacity that may be essential for reliability but is used so rarely that it cannot recover its costs from energy sales?

The answer is capacity payments, regulated cost recovery, or some comparable reliability obligation. But that means the costs of a wind-solar-storage-DEFR system cannot be evaluated only by comparing the energy cost of wind and solar with the energy cost of conventional generation. The full cost must include the dependable backup system, long-duration energy storage, new transmission, distribution-system upgrades, fuel infrastructure, reserve margins, and the cost of maintaining resources for rare but severe weather events.

Nuclear Is the Obvious DEFR

Nuclear power is a proven dispatchable emissions-free resource. It can provide dependable electricity through New York’s winter peaks without relying on wind or sunlight, and its fuel can be stored on site. However, new plants face substantial costs, long construction timelines, and financing risks, but those challenges are better understood than the performance and cost of the still-undefined resources the Climate Act Scoping Plan expects to replace fossil generation.

If New York builds nuclear capacity, it should use it as a primary source of reliable zero-emission electricity—not merely as rarely used backup for a wind, solar, battery, and hydrogen system that still needs dependable generation during prolonged renewable shortfalls.

Conclusion

Estes’ issues with Blackmon’s statement is overly absolute. Wind and solar do not always fail when electricity is needed most. At many times they provide useful, and sometimes very valuable, electricity.  But Estes’s response does not address the more consequential problem for New York’s Climate Act transition.

Wind and solar are weather-dependent resources. There will eventually be extended periods when both are insufficient, particularly during winter conditions when an electrified New York may face its greatest demand. Batteries can help for hours and, with enough investment, perhaps longer. They cannot solve the problem indefinitely unless there is enough energy available to recharge them.  That means New York must have sufficient dependable, fuel-secure, dispatchable capacity to supply electricity through the worst credible periods of low wind and solar production.  Failure to provide that resource in an electric  system overly reliant on wind and solar will create an unacceptable reliability risk.

The state calls that resource category DEFR. Yet it has not demonstrated what technology will provide it, how much will be required, how it will be fueled, whether it can operate for the full duration of the worst case renewable drought, or how ratepayers can afford a resource that may be used only rarely.  Until those questions are answered, claims that wind, solar, and storage can provide an affordable and reliable all-electric energy system are premature.  I do not think that Este’s Substack post adequately addressed DEFR and its necessity for reliability.

New York should stop treating DEFR as an undefined future technology and recognize that nuclear generation is the proven scalable zero-emission resource capable of providing the dependable electricity the state will need when wind and solar cannot.  New York must address this issue as soon as possible.

New York Nuclear Reliability Backbone: Potential and Probability

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

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

Comment Submittal

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

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

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

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

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

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

Consumer Protection is Essential

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

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

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

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

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

The uncomfortable financing question

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

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

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

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

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

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

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

New York’s credibility problem

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

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

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

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

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

Those two requirements are in tension.

My conclusion

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

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

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

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

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

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

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

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

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

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

Background

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

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

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

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

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

Misinformation Examples

Video Link Claim – Savings from Solar Generation

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

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

Video Link Permitting History and Renewable Climate Resiliency

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

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

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

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

Video Link Renewable Energy is Fastest Resource to Deploy

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

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

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

Video Link The Need for DEFRs

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

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

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

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

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

Solar Farms Comments

The following claims are introduced in this slide.

Video Link Leaseholder Investments

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

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

Video Link Conversion Back to Farming

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

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

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

Video Link Comptroller Farmland Protection Audit

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

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

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

Conclusion

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

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

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

Guest Post: Ellenbogen – BESS is Currently a Science Project

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

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

Utility Scale Lithium-Based Energy Storage System Issues

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

Ellenbogen’s argument has three linked elements:

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

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

BESS is Currently a Science Project

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Caiazza Closing Remarks

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

Climate Action Concerns Require More Than Attribution Headlines

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

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

The climate-policy debate has two questions

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

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

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

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

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

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

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

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

The weather-attribution problem

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

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

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

There are legitimate questions to ask about every such claim:

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

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

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

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

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

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

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

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

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

Climate policy cannot repeal weather

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

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

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

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

A genuinely pragmatic approach

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

The required standard should be straightforward:

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

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

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

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

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

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

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

Bad timing: Auction 73 landed the same day

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

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

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

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

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

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

The missing piece: the wholesale-market cost adder

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

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

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

Averages hide who actually pays and who actually benefits

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

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

How much of the 37 percent reduction is actually RGGI?

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

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

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

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

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

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

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

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

What would actually set the record straight

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