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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.

Climate Act Blue Ribbon Commission Affordability Politics

I previously described revisions to the Climate Leadership & Community Protection Act (Climate Act) in the New York State budget bill.   I believe the budget bill addresses some of the most egregious technical and accounting problems I have criticized since 2019, but it leaves my central concerns about feasibility, affordability, and reliability largely untouched.  A key shortcoming in the transition process has been non-existent consideration of input contrary to the political narrative.  This post describes a provision in the budget bill for a “blue-ribbon” commission to address ratepayer affordability that I believe will continue that same approach.

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.  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. 

Overview

The Climate Act (Climate Act or CLCPA) created the Climate Action Council and charged it with developing a Scoping Plan that recommends strategies and policies to achieve the statute’s emission-reduction and clean energy mandates.  The plan was finalized in December 2022 and outlines how New York proposes to implement the Climate Act across all sectors of the economy.

Under the State Energy Law, the New York State Energy Planning Board—made up of agency heads, gubernatorial and legislative appointees, and the NYISO president—develops and adopts a comprehensive State Energy Plan every four years.  The most recent plan explicitly incorporates and advances the Climate Action Council Scoping Plan’s recommendations so that they guide the State’s energy-related decision making through about 2040.

Part TT of the 2026 Budget Bill establishes another appointed group.  This legislation establishes a temporary commission to be known as the blue-ribbon commission on residential affordability through energy savings, or RATES commission.  The RATES commission will “study the causes and origins of rising utility rates and to recommend any actions or reforms to reduce such rates.”

Because the entire RATES commission is appointed by one party, I believe that the findings are pre-ordained to be whatever is politically convenient.  At the top of that list is to claim that the Climate Act has little to do with rising utility rates.

Climate Action Council

The fundamental problem with the Climate Action Council was evident by July 2021, sixteen months after the bylaws were adopted.  The statute emphasized climate‑advocacy and social‑justice perspectives over power‑system engineering, economics, or utility operations, so the Council’s recommendations reflected ideological commitments (electrify everything; rapid fossil shutdowns) rather than an honest assessment of feasibility.  Decisions were made on the presumption of expertise by some Climate Action Council members who have no relevant background or experience on power-system topics.  For example, regarding electric grid reliability, they went so far to state anyone who disagrees with them is a mis-informer.  Paul Shepson, Dean, School of Marine and Atmospheric Sciences at Stony Brook University,  stated at the 26 May 2022 Council meeting recording:

Mis-representation I see as on-going.  One of you mentioned the word reliability.  I think the word reliability is very intentionally presented as a way of expressing the improper idea that renewable energy will not be reliable.  I don’t accept that will be the case.  In fact, it cannot be the case for the CLCPA that installation of renewable energy, the conversion to renewable energy, will be unreliable.  It cannot be.

Another example was Council member Rober Howarth.  Howarth claims that he played a key role in the drafting of the Climate Act and his statement  at the meeting where the Scoping Plan was approved claims that no new technology is needed:

I further wish to acknowledge the incredible role that Prof. Mark Jacobson of Stanford has played in moving the entire world towards a carbon-free future, including New York State. A decade ago, Jacobson, I and others laid out a specific plan for New York (Jacobson et al. 2013). In that peer-reviewed analysis, we demonstrated that our State could rapidly move away from fossil fuels and instead be fueled completely by the power of the wind, the sun, and hydro. We further demonstrated that it could be done completely with technologies available at that time (a decade ago), that it could be cost effective, that it would be hugely beneficial for public health and energy security, and that it would stimulate a large increase in well-paying jobs. I have seen nothing in the past decade that would dissuade me from pushing for the same path forward. The economic arguments have only grown stronger, the climate crisis more severe. The fundamental arguments remain the same.

The “Highlights from the 2025 State of the Market Report for the NYISO Markets” presentation to the NYISO Management Committee by the NYISO Market Monitoring Unit, Potomac Economics on May 27, 2026 included the following slide documenting issues contradicting Howarth’s statement.  The failure of the Climate Action Council to demand a feasibility study and a conditional transition plan because “the conversion to renewable energy would be reliable” has resulted in significant retirements of the resources necessary for reliability and other impacts unacknowledged by ideologues on the Council.

State Energy Planning Board

The same basic problem shows up in the State Energy Planning Board, which is supposed to be the more sober, technocratic body that translates the Climate Action Council’s ambitions into an official State Energy Plan. Under Article 6 of the State Energy Law, the Board is stacked with senior state officials: the heads of ten agencies and authorities, one appointee each from the Governor, the Assembly Speaker, and the Senate Temporary President, and the president of NYSERDA as chair. The only person at the table with direct responsibility for keeping the bulk power system operating, the presiding officer of the federally designated bulk system operator (the NYISO), is there as a non‑voting member.

On paper, the Board is supposed to balance multiple objectives. The statute says the State Energy Plan should improve reliability, protect consumers from price volatility, reduce overall energy costs, and minimize health and environmental impacts. In reality, because the voting members are drawn from the very institutions already committed to the Climate Act agenda, the Board behaves more like an internal ratification committee than an independent check. When NYSERDA announced that the State Energy Planning Board had approved the 2025 State Energy Plan, it emphasized that the Board “comprised of multiple State agency heads, appointees from the Governor, Senate, and Assembly, and the president of the New York Independent System Operator” adopted the plan unanimously and that the Plan explicitly advances the Climate Action Council’s Scoping Plan recommendations.

Notice what is missing from that description: there is no guaranteed voting seat for a consumer advocate whose job is to push back on bill impacts, no requirement for independent power‑system engineers, and no formal role for utility planners or market economists whose professional obligation is to question whether the numbers add up. The NYISO can raise concerns about reliability, but at the end of the day, the NYISO representative does not get a vote when the Board decides whether to bless a plan that folds in the Climate Action Council’s assumptions and timelines. That structure guarantees that any serious challenge to the political narrative — for example, that the pace of mandated retirements is inconsistent with maintaining reliability at reasonable cost — will be treated as a nuisance rather than a core planning issue.

In other words, the State Energy Planning Board is not a neutral referee standing above the Climate Action Council. It is an extension of the same political narrative, organized to give the appearance of comprehensive, expert‑driven state energy planning while insulating the underlying policy from meaningful technical or economic scrutiny. That helps explain why the 2025 State Energy Plan reads more like a translation of the Scoping Plan into agency task lists than a candid assessment of what is achievable without blowing up reliability and affordability.

RATES Commission

The political sales pitch for the RATES Commission is straightforward.  Governor Hochul and the legislature recognize that utility bills are punishing households and are a political liability.  In response they want a “blue‑ribbon” panel to get to the bottom of it. The reactions to Part TT, and the way the membership is structured, suggest what the commission is likely to do—and what it will avoid.

On the supportive side, Assembly leadership, AARP, and several majority legislators point to the RATES Commission as proof that this budget delivers “strong utility reforms,” grouping it with one‑time rebate checks and changes in how PSC and NYSERDA assessments show up on bills. Their messaging emphasizes “cracking down” on utility profits, increasing transparency, and protecting working families from “corporate greed,” not reevaluating the Climate Act. The appointment scheme reinforces that emphasis: all members are named by the Governor and legislative majorities, with designated seats for administration officials and majority‑aligned appointees, and no guaranteed voting role for an independent consumer advocate, power‑system engineer, or NYISO representative.

Business‑oriented groups are more conditional. Upstate United, for example, has framed the commission as a potential vehicle to force transparency around what is really driving costs, especially in upstate regions that have seen sharp delivery and supply increases while being told they already live in a “clean energy success story.” Their implicit challenge is that if the commission is serious about affordability, it must finally addres the full cost of CLCPA implementation, NYSERDA surcharges, and transmission and resource‑adequacy investments that flow directly from the Climate Act.

Republican legislators focus on process and composition: every voting appointment is controlled by the Governor and legislative leaders who supported the Climate Act, the Scoping Plan, and the 2025 State Energy Plan. The absence of built‑in representation for independent consumer advocates, utility planners, or market economists, and the lack of a voting role for NYISO, signals that the same political coalition that designed the transition will decide which rate drivers are fair game for criticism.

Given that context, it is not hard to predict how the RATES Commission will treat Climate Act cost drivers and NYISO reliability warnings.  It is politically easier for the commission to treat Climate Act‑driven spending as non‑negotiable “public policy costs,” blame rising bills on utility behavior and generic “infrastructure needs,” and recast NYISO’s reliability warnings as implementation problems rather than evidence that the mandates themselves are out of sync with what the power system can safely deliver.

Conclusion

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 CLCPA transition. In other words, given who will sit on it and who won’t, the RATES Commission is unlikely to be the place where New York finally confronts the affordability and reliability consequences of implementing the Climate Act as written; it is more likely to become an additional layer of political insulation around a transition whose costs and technical risks remain off‑limits.

Independent Power Market Analysis Confirms My Concerns About RGGI

Over the past several months I have published a series of posts arguing that the Regional Greenhouse Gas Initiative (RGGI), as currently structured, no longer serves its stated purpose of reducing greenhouse gas emissions and has become a significant, largely unacknowledged burden on electricity consumers throughout the RGGI states. I found independent corroboration from two white papers published by Tabors, Caramanis, and Rudkevich (TCR), an energy consulting and analytics firm. The convergence of conclusions reached through entirely different methodologies — my narrative and historical analysis versus TCR’s full power market simulation — is, I believe, significant and worth examining in detail. 

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.  I acknowledge the use of Perplexity AI to generate references and draft text included in this document. 

The Two White Papers

TCR published two relevant papers. The first, dated February 15, 2025, is titled Summary Impact of RGGI on Electricity Prices and Generation Fleet Operation in the PJM Interconnection and was authored by Dr. Aleksandr Rudkevich and Dr. Richard Tabors. It uses TCR’s ENELYTIX power market simulation tool to model the PJM wholesale electricity market across a full calendar year (2025) under two scenarios: a Business-as-Usual case in which Delaware, Maryland, and New Jersey participate in RGGI at $20 per short ton of CO₂, and a No-RGGI case in which no PJM state participates. The $20/ton price reflects the RGGI forward market in October 2024, when the work began.

The second white paper, dated April 1, 2026, is titled Quantitative Evaluation of a RGGI Fixed Price Proposal for New Jersey and models a specific reform proposal: setting the RGGI compliance price to a fixed $7 per short ton for New Jersey generators, compared to a base case in which New Jersey operates under the Cost Containment Reserve (CCR) Tier 2 Trigger Price of approximately $29.25/ton. That paper also includes a sensitivity analysis examining what happens if Virginia re-joins RGGI in 2028. The study period is 2027–2030.

Where the Analysis Converges: The Emissions Leakage Problem

The event that solidified my belief that changes are in order was the fallout from the April 29, 2026, RGGI statement that Virginia was rejoining the program.  I explained  in the days that followed, the futures market price of RGGI allowances nearly doubled, and the spot market cost also increased significantly.  The closing price of the most recent RGGI auction on June 3, 2026, was $35.00 up 40% from the March 11, 2026 auction price of $24.99.  One of the implications of this increase in price is that emissions leakage from RGGI states to now cheaper sources in non-RGGI states is no longer a theoretical problem.

The core analytical finding of the TCR 2025 white paper confirms the leakage observation from a different direction: RGGI, at current prices, does not reduce carbon dioxide emissions in any net sense. Because there are states in RGGI and not in RGGI in the PJM Interconnection this effect is magnified.  The higher RGGI prices redistributes where generation and  emissions occur, and because it displaces efficient gas-fired combined-cycle generation in RGGI states with less-efficient coal-fired generation in non-RGGI PJM states, the net effect is a larger total emissions footprint.

TCR’s simulation is precise about the mechanism. Under RGGI at $20/ton, the allowance cost adder renders highly efficient combined-cycle power plants in Delaware, Maryland, and New Jersey uneconomical in the PJM dispatch stack. The gap is filled by coal-fired units located in western PJM — in states like Ohio, West Virginia, and Pennsylvania — that face no RGGI compliance obligation. The quantitative result from TCR’s Figure 1 is striking: RGGI causes combined-cycle gas generation to fall by 6,850 gigawatt-hours, while coal generation increases by 5,220 GWh and other thermal generation rises by another 628 GWh. The net CO₂ impact, shown in TCR’s Figure 2, is a system-wide increase of 2.7 million short tons per year. Emissions fall by roughly 3 million short tons in the RGGI-participating zones as gas-fired CC plants run less — but they rise by 5.7 million short tons in the rest of PJM as coal and other thermal plants fill the void.

My recent post on Virginia and the myth of lower energy costs made the identical analytical argument, estimating a net emissions increase attributable to the leakage mechanism. The TCR 2025 paper confirms this with precision. It also notes a secondary concern I raised as well: RGGI’s effect on PJM exports reduces sales to MISO and other neighboring grids by approximately one terawatt-hour, likely causing further emission increases in those systems — a second-order leakage effect that is not counted in the headline figure.

It is important to note that TCR modeled RGGI at $20/ton. As of the most recent auction in June 2026, RGGI allowances cleared at $35/ton — 75% higher than the TCR assumption. The leakage and cost impacts TCR documented are therefore considerably worse today than their published numbers reflect.

Where the Analysis Converges: Consumer Cost Impacts

The TCR 2025 paper quantifies the consumer cost impact across the entire PJM footprint at $1.16 billion per year in additional costs (expressed in constant 2024 dollars) for the $20/ton scenario. This arises from two mechanisms that I have described. First, RGGI-obligated generators embed the allowance cost directly in their market bids. Second — and this is the more important and less-understood effect — when a RGGI-obligated unit sets the market clearing price, every generator in that pricing zone collects the higher clearing price, including non-emitting units that have no compliance obligation whatsoever. Those zero-emission units receive the carbon cost premium as pure profit without bearing any direct CO₂ compliance cost.

My May 9, 2026 post on RGGI’s unacknowledged New York cost impact described this mechanism and concluded that total consumer costs can be “two or more times higher than the direct allowance expenditures.” The TCR paper’s system-wide $1.16 billion figure, modeled at $20/ton, is consistent with that characterization. The primary beneficiaries TCR identifies are generators located in non-RGGI PJM states, which receive nearly $1.3 billion per year in additional revenues as a result of the program. RGGI-state generators actually see their revenues reduced by approximately $500 million per year, for a net revenue transfer to non-participating states of $825 million annually. Consumers in RGGI states are, in effect, subsidizing coal-state generators through their electricity bills.

The Historical Attribution Problem

This is an area where my analysis goes meaningfully beyond what either TCR white paper addresses. Both TCR papers acknowledge the historical emission reduction record of the RGGI program: the three PJM participants (Delaware, Maryland, and New Jersey) collectively reduced in-state CO₂ from 44.8 million short tons in 2009 to 23.6 million short tons in 2024 — a net reduction of 21.2 million short tons. The TCR papers present this as RGGI’s achievement without examining the counterfactual question: how much of this reduction would have occurred anyway?

My December 2025 post analyzing New York’s RGGI Cap-and-Invest emission reduction performance addresses that question directly, at least for New York. By examining NYSERDA’s own program investment data, I calculated that total cumulative annual emission savings from RGGI-funded investments through 2023 amounted to approximately 1.4 million tons — meaning that emissions from RGGI sources in New York would have been only about 3% higher in the absence of any RGGI investment spending. My Virginia post extended the analysis to the broader program, estimating that roughly 7.6% of observed reductions can be attributed to RGGI-funded projects; the remaining 93% or more reflect market-driven fuel switching from coal and oil to natural gas, driven by price differentials that had nothing to do with RGGI allowance costs.

The TCR white papers take the reduction record at face value. This is not a criticism — attribution analysis was outside their scope — but it means the papers’ own historical framing somewhat overstates RGGI’s contribution during its early years. The combination of the TCR findings and my attribution analysis leads to a more complete picture: RGGI may have modestly reinforced a reduction trend it did not create, while today it has reversed sign and is now adding to system-wide emissions rather than reducing them.

The Reform Scenario: The NJ $7 Proposal

The TCR 2026 white paper breaks new and useful analytical ground by evaluating a specific structural reform. New Jersey has been exploring a proposal to fix the RGGI compliance price for its generators at $7 per short ton — far below both the current market clearing price and the CCR Tier 2 cap of $29.25/ton used as the 2026 paper’s base case. TCR’s simulation of this proposal is revealing: the $7 fixed-price scenario would reduce PJM-wide CO₂ emissions by an average of 4.7 million short tons per year relative to the high-price base case, and would save New Jersey consumers approximately $274 million per year in wholesale energy costs.

The mechanism runs exactly in reverse of the high-price leakage problem. At $7/ton, the compliance cost adder for New Jersey’s efficient combined-cycle generators is small enough that they remain competitive in the PJM dispatch stack against non-RGGI coal plants. Gas-fired CC units in New Jersey dispatch more, coal plants in western PJM dispatch less, and system-wide emissions fall. The program at $7/ton functions more like a modest carbon fee that funds state clean energy investments without distorting the dispatch order in harmful ways — which is, notably, exactly how RGGI functioned during its first decade, when prices were generally below $5/ton.

This analysis raises a question worth exploring in future posts: is the concept of RGGI broken, or is it the current price level that has broken RGGI? The TCR 2026 paper’s findings suggest the latter. A reformed RGGI with substantially lower and more stable allowance prices might actually accomplish what the program’s proponents claim it does today — reduce emissions without imposing unacceptable consumer costs. At current prices, those claims are simply not supported by the evidence.

The Virginia Complication

Both my May 2026 post on Virginia’s rejoining and the TCR 2026 sensitivity analysis point in the same direction: Virginia re-entering RGGI at current price levels makes matters worse, not better. The TCR 2026 paper finds that baseline costs to New Jersey consumers are lower when Virginia is not a RGGI participant, and that the CO₂ emission reductions achievable through the NJ $7 Proposal are larger when Virginia stays out. My own compliance analysis found that Virginia’s addition tightens the allowance pool and is likely to accelerate the depletion of available allowances, which I project runs out in the third quarter of 2033 at constant emission rates.

What makes the Virginia situation particularly concerning is the price signal. When Governor Spanberger’s commitment to rejoin RGGI was announced in November 2025, RGGI futures prices rose more than 30% in three days, breaking all-time highs above $40/ton. That price spike immediately flowed into generator bids and was “showing up in electric prices” as I noted at the time. RGGI’s volatility at current scarcity levels — any news about program participation moves the market sharply — compounds the cost problem for consumers and the planning problem for grid operators.

The Bottom Line

The TCR 2025 white paper’s own “Bottom Line” section (Section 4.4) contains language that I could have written: the continuation of RGGI in its current form “contradicts RGGI’s principal intent, which is to reduce greenhouse gas emissions,” and the program “appears, quite clearly, to have outlived its stated objective in PJM and from a policy perspective is in need of significant realignment if not elimination.”

That conclusion, reached by professional power market economists using rigorous quantitative simulation, validates the core argument I have been making my work through historical and analytical work. Two independent lines of inquiry — one empirical and narrative, one formal and computational — have converged on the same answer.

The path forward is not necessarily to abandon carbon pricing in the electricity sector. The TCR 2026 paper’s $7/ton analysis suggests that a reformed program with much lower and stable prices could work better on both the cost and environmental dimensions simultaneously. But the current program, at current prices, with the current cap trajectory, is failing on both dimensions at once. Proponents who continue to claim that RGGI reduces emissions and lowers consumer costs now have two independent analyses to refute — not just my work.

Out of Control New York State Renewable Developers

Fred Stafford has put together a comprehensive look of the New York State (NYS) renewable development process administrated through the New York State Energy Research & Development Authority (NYSERDA). He shows how the state’s renewables developers dumped their project risk onto the backs of ratepayers but without the open scrutiny that the state applies to utilities. He also provides a comprehensive look at renewable projects in New York.

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, 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. 

Background

NYSERDA’s renewable procurement role looks like a neutral administrative function on paper, but it has turned into a highly centralized process that papers over the practical risks of New York’s climate agenda while shifting cost and execution risk onto ratepayers. The Clean Energy Standard and subsequent orders anoint NYSERDA as the “central clean energy procurement agency,” steadily increasing its annual targets even as an uncomfortable share of its contracted portfolio never makes it to commercial operation. That structure suits the Hochul Administration and activists because it allows big press releases about “nation‑leading” awards while the messy details of cancellations, repricing, and cost escalation disappear into a complex tangle of Renewable Energy Credits (REC) and Offshore Wind Renewable Energy Credits (OREC} contracts.

To its credit, NYSERDA is fairly candid in some filings and interviews about underlying structural problems.  There can be a three‑ to six‑year lag between a bid and the start of a contract during which global cost conditions can swing wildly. A bid that looked “cheapest” in year one can be hopelessly underwater by the time a project is ready to build, at which point everyone faces an ugly choice between swallowing higher costs or losing the project. Instead of rethinking this model, the state has chosen to pile on larger annual procurement targets and give NYSERDA more discretion to tweak terms, hoping better central planning will overcome siting bottlenecks, NYISO interconnection constraints, and macroeconomic headwinds.

While NYSERDA has admitted in some instances that there are issues with renewable procurements, they have not provided a detailed assessment of the programs and their status.  Fred Stafford details what has happened to renewable contracts over the last three years.  In short the developers threatened to cancel their projects unless NYS coughed up more money.  He also has compiled the first comprehensive look at what happened to each of the 86 projects that the renewables industry cited in its threat of cancellation.

Renewable Development Shakedown

Stafford describes what has happened in NYS:

Back in June 2023, the trade group representing New York renewables developers, Alliance for Clean Energy New York (ACE NY), warned the state that, due to post-COVID supply chain issues and inflation, their 86 wind and solar projects under development were facing cancellation. That amounted to about 7.5 GW of new power generation at risk.

Each of the projects held a contract with NYSERDA, the state’s energy procurement agency, to receive subsidies in the form of renewable energy certificates (RECs), a project revenue stream on top of the actual sales of power. Having all competed for, and won, these contracts in annual auctions between 2016 and 2021, the developers were concerned the subsidies wouldn’t yield enough return on investment for their shareholders. The developers of four offshore wind projects and the ill-fated Clean Path NY transmission project all followed suit: our competitively won subsidies need to be increased.

To remedy their financial predicament and to save the projects, ACE NY requested that the state renegotiate their contracts by adjusting the REC prices with an inflation index. If the state refused their request then many of the developers would be forced to terminate their projects. But without these projects, ACE NY argued, not only would the state’s statutory climate goals be in jeopardy, so too would its electric reliability. After all, the only significant new power generation winning investment in New York these days is renewable.

The ACE NY petition fleshes out the threat to reliability posed by the cancellation of their projects. Here’s an example: “… [D]elays in renewable energy development would only exacerbate the reliability risk already implicated in recent reports and undercut the State’s commitment to developing the resources necessary to effectively combat climate change.” NYPSC Case 15-E-0302, Petition of the Alliance for Clean Energy New York to Address Post COVID-19 Impacts on Renewable Development Economics and Contract Considerations (filed June 7, 2023, revised June 12, 2023), pp. 34-35.

New York needed the developers’ projects and therefore needed to increase their subsidies beyond the competitively determined contractual prices. The developers had the state under their thumbs and both sides knew it. Other trade groups and nonprofits that push renewable energy even backed them up in demanding inflation adjustments, as did labor unions, whose members’ livelihoods were predicated in part on building the projects.

In October 2023 the state’s Public Services Commission nonetheless voted unanimously to refuse the request for inflation adjustment to existing contracts. In a statement, ACE NY’s director Anne Reynolds painted a picture of doom and gloom. “Unfortunately, today’s action by New York is not a sign that our state is really committed to the climate change action mandates that exist in law, and it is not a day that has moved us forward in giving future generations of New Yorkers a healthier and safer environment,” she said.

But the state wanted to preserve competitive procurement as the way to develop new electricity resources at lowest cost to ratepayers. “By rejecting this relief, we signal to every vendor that our contracts, our commitments are worth the paper they are written on,” PSC Chair Rory Christian stated at the time. “We signal that ratepayer funds are not an unlimited piggy bank for anyone’s disposal.”

Instead, the PSC ordered a new, expedited 2023 auction for renewables subsidies, held shortly before the regularly scheduled 2024 auction.  The new auctions also included an optional inflation adjustment index that would apply to the final strike price once the project was finished with construction. This was a major ask from the ACE NY petition, and they largely got it. Any of those 86 projects that wouldn’t pencil for their investors under existing contracts could be cancelled, and developers could simply re-bid for subsidies in the new auction. Since they’re organized politically into a trade group that presses the state on the need for higher subsidies, they could be sure that the subsidies in the new auctions, a result of all their competitive bids, would be higher.

And that’s exactly what happened: a majority of these projects’ developers ultimately cancelled their contracts, re-bid in the subsequent auctions, won even higher subsidies from ratepayers, and continued with the projects.

The fate of the offshore wind projects that issued the same demand is better understood, given the smaller count. Each of the four cancelled their contracts and two of them won contracts for higher prices than what they’d won back in the 2018 auction. Empire Wind 1 gained a 27% increase in its subsidy, while Sunrise Wind scored a 32% increase.  See Table 5 in this research on offshore wind for a clear presentation of the New York offshore wind solicitations timeline and increase in strike prices. Hansen, Tyler A., et al. “Institutional learning in the energy transition: The case of offshore wind in the United States.”

Contract Tracking Analysis

As is the case with anything associated with NYSERDA documentation for the Climate Act there is NYSERDA data available but getting it all together is not straight forward.  I cannot over-emphasize my admiration of the work Stafford did to put together a spreadsheet documenting the fate of the 86 projects.  He explains:

Projects show up with slightly different names, perhaps different developers, in periodic reports. One must use their NYISO interconnection queue positions and their state siting cases, both of which are included in state data, to track their progression over time.

Even determining the actual list of 86 projects requires some footwork, as ACE NY’s petition didn’t list them out.4 ACE NY characterized the 86 projects as the subset of the 117 Tier 1 land-based wind and solar contracts, from 2016 to 2021 procurements, that were considered “Under Development” as of June 2023. See Table 14, NYPSC Case 15-E-0302, Petition of the Alliance for Clean Energy New York to Address Post COVID-19 Impacts on Renewable Development Economics and Contract Considerations (filed June 7, 2023, revised June 12, 2023), Attachment A, pp. 23.Because NYSERDA’s data hides earlier snapshots, I had to rely on lucky Archive.org snapshots of it to reconstruct that list. They’re all the land-based wine and solar Tier 1 projects from 2016 through 2021 auctions that were, at the time of the June 2023 petition, still listed as under development. See the “project roster” tab in my spreadsheet.

Results Overview

Stafford summarizes the results:

Of the 86 wind and solar projects that ACE NY demanded higher subsidies for, totaling 7.5 GW, a majority of that capacity, 4.1 GW, consisted of projects that eventually re-bid and won contracts in the subsequent auctions that NYSERDA ran.

  • 20 of them (2.0 GW) won contracts, at much higher prices (see next section), in the late 2023 auction.
  • 18 of them (2.1 GW) won contracts in the 2024 auction, whose price outcomes are not yet public.
  • 8 of them (650 MW) submitted bids for contracts in the 2025 auction, which is still being evaluated.
  • 6 of them (357 MW) continued to completion on their original NYSERDA contracts.
  • 34 of them (2.4 GW) were simply abandoned by their developers, so far.

The ones that won contracts in 2023 scored subsidies that were 20 to 64% higher

He explains that the project status is still evolving:

Note that we can’t argue yet that a majority of the 86 projects won contracts after rebidding. The 2025 procurement auction is currently ongoing, so we don’t know which of the 8 projects from the petition set will actually win contracts based on their bids. In the 2023 auction, 48 of the 86 submitted bids but only 20 won, and in the 2024 auction, 25 of the remaining 86 submitted bids but only 18 won.

Discussion

The NYSERDA bidding process is rigged against consumers.  While PSC Chair Rory Christian said that “We signal that ratepayer funds are not an unlimited piggy bank for anyone’s disposal.”  The facts show that the renewable energy lobby led by ACE-NY blackmailed NYS into re-bidding renewable energy contracts and that when the contracts were re-bid the piggy bank was cracked open.  The lawmaker advocates for the Climate Act did not require a feasibility analysis to determine whether an electric system that relies on wind, solar, and energy storage can maintain current reliability and affordability standards.  Instead they opened up NYS to renewable developers to build as much as they can, as fast as they can and in the process documented By Stafford essentially guaranteed rates of return that represent a regressive tax on all utility bills.

NYSERDA’s procurement responsibilities are not a neutral back‑office function; they define how risk, cost, and accountability are distributed across the entire Climate Act build‑out. By keeping so much of the action behind the curtain of complex contracts, the current setup enables a steady stream of “bold” announcements about new renewable and offshore wind awards, even as the roster of operating projects grows more slowly and the affordability and reliability implications become harder to ignore. That gap between promises and projects is not a surprise failure of an otherwise sound system; it is an entirely predictable outcome of a procurement model that prioritizes optics and statutory compliance over realistic timelines, durable contracts, and transparent evaluation of costs and benefits.

Conclusion

Stafford concludes:

The whole point of moving from utility monopoly to competitive markets for electricity generation was to lower costs by putting project risk onto investors and not onto ratepayers. Here we have a fully competitive procurement system and yet the investors managed to collectively exert some political pressure and shift the project risk back onto ratepayers. All it took was canceling their contracts, waiting for later auction processes, and acting collectively to bid much higher prices for those subsidies.

That’s because New York’s electricity system is not some testbed of pure competition, pure price signals, and autonomous, uncoordinated agents. The state has a grid that desperately needs new generation and it has climate goals that desperately need new renewable projects. The renewables developers have demonstrated their capacity to work collectively, through ACE NY, to push a narrative about their common industrial and financial situation. Of course it’s in large part true: COVID did create major new supply chain snarls and inflationary pressures.

But unlike in the old electricity market, where investment in generation came from the state’s utilities, the New York Public Services Commission has no corporate books to look at, no ability to regulate profits to ensure that investors aren’t making out like bandits. Instead, they can only trust the developers and read the tea leaves of the market, and hope that these iterations of competitive procurement aren’t producing huge windfalls for the projects’ ultimate investors. Maybe there was something important lost in that old way of doing things.

NYISO 2026 Power Trends – Reality is Catching Up

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 says many of the right things, even if it still does not say them quite as bluntly as the situation deserves. The report acknowledges that electrification, large new energy-intensive loads, retirement of conventional resources, and weather-dependent generation are combining to make the system more uncertain and more fragile. It also says reliability margins are shrinking and that winter conditions are becoming a defining challenge. That is an important step forward, but it is also an implicit admission that the Climate Leadership & Community Protection Act (Climate Act) implementation process has been pushing the grid toward a level of risk that the state has not honestly grappled with.

I have written over 650 articles about the Climate Act and 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.  The opinions expressed in this post and in my filing do not reflect the position of any of my previous employers or any other organization with which I have been associated; these comments are mine alone.  I acknowledge the use of Perplexity AI to outline this post and draft the text used in this document. 

Power Trends 2026

The Executive Summary states:

Power Trends explores the issues shaping New York’s electric system as it undergoes a historic transformation driven by simultaneous changes in supply, demand, and infrastructure.

The report highlights increasing and more uncertain electricity demand, a changing generation mix, and a system that is more geographically dispersed, weather‑dependent, and operationally complex. Maintaining reliability depends on disciplined planning, timely investment, and market structures that align investment with system needs and value operational performance during stressed conditions.

NYISO provides the report, a key trends fact sheet, a note from the NYISO president and CEO, and report figures and resources.

Key Findings

The report highlights five big trends: declining reliability margins, rapid and uncertain load growth, shifting seasonal risks, a changing resource mix, and expanding system uncertainty. That is a polite way of saying the grid is getting harder to run while the policy environment keeps adding complexity. NYISO is also explicit that the system needs generation, storage, transmission, and demand-side solutions that can perform during extended periods of high demand.

The press release makes one point especially clear: NYISO wants an “all-of-the-above” investment approach supported by competitive markets. In plain English, that means New York cannot afford to bet the system on a single preferred technology or an aspiration about how fast a transformation will happen. It needs resources that are available when needed, not just resources that look good in a policy presentation.

Where this fits my concerns

My long-running concern with Climate Act implementation has been that the process has treated emissions targets as if they were operational plans. The result has been an unfortunate habit of confusing policy preference with system capability. NYISO’s report does not use that language, but it does describe the consequences: less margin for error, greater weather dependence, more uncertainty, and increasing pressure on winter operations.

That is exactly the kind of caution that should have been part of the implementation process from the beginning. Instead, the state has often acted as though the answer to every reliability question was “more renewables, more quickly,” with insufficient attention to the timing and performance of the resources that keep the lights on. NYISO now says the system needs disciplined planning and timely investment, which is a far cry from the casual optimism that has often accompanied Climate Act roll-out discussions.  I remain concerned that there still are unresolved differences between the New York State Energy Research & Development Authority (NYSERDA) implementation descriptions of the transition in the Scoping Plan and the State Energy Plan and NYISO planning reports.

The report also reinforces a point that has been obvious for years: load growth is not a static assumption anymore. Electrification, data centers, and other large projects are changing demand in ways that can swamp neat planning narratives. The idea that energy efficiency and energy conservation efforts will prevent load growth is also no longer valid.  That means the state’s implementation process should be more conservative, not less, because uncertainty is rising on both the supply and demand sides.

Not so Independent NYISO

One reason NYISO’s documents are often carefully crafted to not contradict NYSERDA’s transition planning documents is that they must operate in a political environment where outright candor can be punished. That does not mean the report is wrong; it means the language is often muted. In my view, that restraint is not accidental. It reflects years of pressure on NYISO to avoid sounding too skeptical about the transition path the state has chosen.

“Energy Czar” Richard Kauffman’s role in that pressure campaign should not be forgotten. In 2016 NYISO filed comments with the state saying its goal to power the state with 50 percent renewable energy by 2030 was unrealistic unless a massive investment in new transmission lines were undertaken.  Kauffman sent a letter saying it was misleading, incomplete, and grossly inaccurate.  Even though the NYISO filing has since proven to be correct NYISO has every incentive to soften language that might be interpreted as resistance. I believe that dynamic has contributed to NYISO documents pulling their punches when discussing the risks of the zero-emissions transition and the practical limits of the Climate Act pathway.

That matters because the public needs more than carefully crafted phrases about “uncertainty” and “scenario-based planning.” It needs a frank explanation that the current policy path creates real reliability risks unless the state changes course on pace, technology assumptions, and resource adequacy. NYISO is getting closer to that point, but it is still speaking in institutional code.

What the report gets right

To NYISO’s credit, Power Trends 2026 is not a celebratory document. It acknowledges declining reliability margins and says retirements and performance problems are outpacing additions to supply. It recognizes that winter is becoming a defining reliability season. It also states that a diverse resource mix is necessary, including generation, storage, transmission, and demand-side measures.

That is a welcome correction to the oversimplified narrative that has dominated much of Albany’s energy policymaking. The report’s emphasis on competitive wholesale markets is also important because markets are where resource adequacy should be tested in practice, not in press releases. If policymakers want reliable electricity, they should listen carefully when the grid operator says performance under stress matters.  It would also be appropriate for the press to qualify any transition story lauding renewables with the concerns described in this report.

What it leaves unsaid

Even so, the report still avoids saying the most uncomfortable thing plainly: Climate Act implementation has been moving faster in policy than in infrastructure. That gap is the heart of the problem. You can mandate a future, but you cannot mandate transmission buildout, generator construction, interconnection readiness, or seasonal fuel security on a slogan-driven schedule. This means that the transition schedule must be reconsidered.

The report also does not dwell on the institutional failure implied by repeated assurances that the transition is manageable without significant tradeoffs. NYISO is now warning that the system’s margin for error is shrinking. That should be read as a warning not just about the grid, but about the policy process that created these pressures in the first place.

A better reading of the outlook

The right takeaway from Power Trends 2026 is not that New York should abandon decarbonization. It is that the future electric system must be treated as an engineering problem, not a moral assertion. Reliability, affordability, and emissions all matter, but they do not obey the same timeline, and they certainly do not respond well to wishful thinking.

Nowhere is this more evident than the undeniable need for Dispatchable Emissions-Free Resources (DEFR). Power Trends 2026 defines this as:

 A resource designed to provide reliable, on-demand electricity without emitting carbon. Unlike intermittent renewable sources like wind and solar, DEFRs can be dispatched as needed to meet demand. Many of the potential technologies are still in development and may face challenges in terms of economic viability and scalability

My concern is that DEFR is indispensable for a wind an solar dependent system, yet there is still no concrete plan to commercialize and deploy any DEFR technology at the scale required. Significant technical, economic, and regulatory uncertainties remain for all proposed DEFR options, so assuming a viable solution will simply emerge when needed amounts to taking an extraordinary reliability risk with the bulk power system.  If nuclear ultimately proves to be the only practical DEFR candidate, then a grid architecture centered on wind, solar, and short duration storage cannot be implemented reliably without large scale nuclear generation. However, nuclear power is best suited to continuous, high-capacity factor operation, so holding it in reserve as an infrequently used DEFR “backup” misuses the technology and wastes its economic advantages.  This problem should be resolved sooner than later.

If the Climate Act implementation process is to become credible, it needs a more honest accounting of resource availability, winter performance, the lead times for transmission and generation, and DEFR technology. NYISO’s latest outlook is useful because it points in that direction, even if cautiously. The report should be read as a signal that reality is asserting itself over rhetoric.

Conclusion

The most important thing about Power Trends 2026 is that it reflects a system under stress and a planning environment that has grown much more complicated than policymakers seem willing to admit. NYISO is telling us that New York needs a broad, reliable, market-based resource buildout, not a narrow ideology dressed up as planning. That is exactly the direction the state should have taken from the start. Instead, it is now being forced to catch up with the consequences of the flawed Climate Act and State Energy Plan implementation process. New York policy has talked as though ambitious emissions targets could be translated into real-world electric system performance simply by declaring them so. NYISO’s latest power trends report is a reminder that physics, infrastructure lead times, fuel availability, and operating reserves do not care about slogans.

Virginia, RGGI, and the Myth of Lower Energy Costs

The Acadia Center recently published a post titled “Virginia is for Lovers, and RGGI is for Lower Energy Costs,” arguing that Virginia’s reentry into the Regional Greenhouse Gas Initiative (RGGI) will make energy more affordable. That narrative is increasingly at odds with both recent auction results and the actual mechanics of how RGGI costs flow through wholesale power markets and retail bills.  This post explains why the Acadia Center story is incomplete at best and dangerously misleading at worst.

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.

What Acadia Center Claims

Acadia Center’s RGGI advocacy rests on a familiar trilogy of claims: emissions have fallen faster in RGGI states, retail electricity prices are lower than in non‑RGGI states, and reinvestment of auction proceeds delivers bill savings that outweigh allowance costs.

In its RGGI materials, Acadia Center touts that:

  • CO₂ emissions from covered power plants are down nearly 50 percent in RGGI states since 2008.
  • Economic growth and per‑capita GDP have been stronger in RGGI states than elsewhere.
  • Retail electricity prices in RGGI states fell by about 3 percent while prices rose nearly 8 percent in other states over roughly the same period.
  • Over 8 million households and 400,000 businesses have benefited from RGGI proceeds, with claimed future bill savings of more than 20 billion dollars.

Acadia then projects this regional story onto Virginia, arguing that carbon pricing revenues can fund energy efficiency and bill assistance programs that will leave households better off.

What these talking points omit are: what actually drove the emissions reductions, how small the RGGI “signal” is relative to other factors, and how the RGGI cost adder interacts with today’s tight supply‑demand balance and rising load from data centers and electrification.

Emissions Fell Mostly Because of Fuel Switching

Acadia’s headline claim is that RGGI caused power‑sector CO₂ emissions to fall roughly 40 to 50 percent in the region. Figure 1 plots CO₂ emissions from all programs and all fuels in the eleven RGGI states from 2006 to 2025. The pattern is clear: emissions dropped primarily because of fuel switching from coal and oil to natural gas, not because of the modest CO₂ price RGGI imposed for most of its history.

Figure 1: Eleven State RGGI CO₂ Emissions (short tons) for all Programs 2006–2025

When I analyzed the 2023 RGGI investment proceeds report, I estimated that only about 7.6 percent of observed emission reductions could be attributed to RGGI‑funded projects, despite more than 7 billion dollars in auction proceeds since 2021. In other words, more than 90 percent of the emission reductions RGGI proponents celebrate came from factors that would have occurred with or without a RGGI cap‑and‑trade overlay.

If the emissions reductions were largely driven by cheap gas and non‑RGGI policy mandates, then it is intellectually dishonest to claim RGGI “delivered” those reductions and associated economic benefits. That matters for the future of RGGI, because the low‑hanging fruit from fuel switching has already been picked; repeating history is not an option.

Auction Prices Have Exploded

Acadia Center describes RGGI costs as a “very, very small percentage” of overall bills. That might have been a defensible talking point when allowance prices were in the single digits or low teens. It is no longer tenable at current levels.

The June 3, 2026 RGGI auction cleared at 35 dollars per ton, a 40 percent jump from the March 11, 2026 auction price of 24.99 dollars (Figure 2). RGGI itself acknowledged the affordability problem in its Auction 72 announcement, stating that the states intend to begin a scoping process to “continue to achieve reliable, clean electricity supply at affordable prices.”

Figure 2: RGGI Quarterly Auction Clearing Price

In 2025, RGGI‑affected sources emitted 86.4 million tons of CO₂, and the average auction price was 22.09 dollars per ton. That translates to 1.94 billion dollars in direct allowance costs to cover auction purchases. At a 35‑dollar allowance price, holding emissions constant, the direct cost rises by about 1.32 billion dollars to roughly 3.02 billion dollars per year.

These are not trivial numbers; they are large, recurring cost streams that must be recovered from someone. In practice, that “someone” is ratepayers across the region, including Virginia households and businesses once the state reenters.

The Hidden RGGI Cost Adder in Wholesale Markets

Acadia’s narrative focuses on what states do with auction revenue but ignores the way RGGI costs propagate through wholesale electricity markets. This omission is critical, particularly for a state like Virginia embedded in PJM with a large data‑center‑driven load growth problem.

When generators bid into daily wholesale markets, they embed the cost of RGGI allowances into their marginal energy bids. If the clearing price is set by a RGGI‑affected unit, then the clearing price includes the CO₂ allowance cost adder. Every unit dispatched at that price – including generators that do not have RGGI compliance obligations – gets paid the RGGI‑inflated clearing price.

The result is a two‑part cost impact:

  • Direct compliance cost: RGGI‑covered generators pay for allowances, which they recover through higher energy prices.
  • Indirect windfall cost: Non‑RGGI‑covered units receive higher revenues than they would have absent RGGI, because clearing prices are higher, even though they have no compliance costs.

In New York, I estimated that this market cost adder alone – the difference between what consumers pay in wholesale markets and the actual compliance costs – runs on the order of 1 to 3 billion dollars per year. Scaling that effect across all RGGI states suggests a regional market impact between roughly 2.7 and 8.1 billion dollars annually, depending on assumptions about generation and price formation.

Acadia Center’s claim that RGGI is an “energy affordability tool” glosses over this wholesale market dynamic, treating auction revenue as free money rather than as a tax on every megawatt‑hour consumers buy. For Virginia, plugging into this system at current prices means willingly imposing an added 10 to 20 dollars per megawatt‑hour on wholesale prices, according to industry estimates, just as bills are already under pressure from new infrastructure and load growth.

RGGI’s Cap Trajectory Is Detached from Reality

Acadia’s storyline assumes that RGGI’s cap trajectory is a reasonable reflection of technical and economic reality. The updated cap path adopted in mid‑2025 tells a different story.

I have found that the new cap reduction schedule cuts allowances by more than 10 percent of the 2025 budget each year from 2027 through 2033. The region has never sustained reductions of that magnitude, and recent years have seen emissions rise due to load growth and delays in clean generation deployment.

Once banked allowances are accounted for, my modeling indicates that the system could effectively “run out” of allowances as early as the second quarter of 2032. At that point, compliant units would face a choice between shutting down or operating out of compliance, neither of which is compatible with a reliable, affordable electric system (Figure 3).

Figure 3:  Quarterly RGGI Allowance Balance, Emissions and Allowance Cap

RGGI’s own Auction 72 announcement admits that cost containment measures have already been exhausted in 2026: the primary cost control mechanism, the Cost Containment Reserve, was fully released in Auction 71, and no additional CCR allowances were available in Auction 72. When Virginia rejoins RGGI there will be another tranche of CCR allowances that I am sure will be released in the next auction.  The market is signaling that the current cap path is too tight relative to realistic deployment trajectories for replacement generation.

Acadia Center ignores this looming supply‑demand imbalance in allowances, treating RGGI as a steady‑state policy rather than a program on track to collide with physical and economic constraints in the next decade.

Who Really Benefits from RGGI Revenue?

Acadia emphasizes that RGGI has generated over 9 billion dollars in proceeds, which states have invested in energy efficiency, clean energy, and bill assistance, benefiting millions of households and hundreds of thousands of businesses. That is technically true; those dollars do fund programs. The question is whether the emission reductions and bill savings they buy justify the costs – and whether the distributional impacts are as progressive as advertised.

My review of the 2023 RGGI investment report concluded that auction proceeds are being deployed inefficiently, with implied cost per ton reduced far above commonly cited social cost of carbon values. RGGI‑funded projects explain only a small fraction of observed emission reductions, while consuming billions of dollars in ratepayer‑funded resources.

Acadia’s “energy affordability” framing implies that these investments more than pay for themselves on consumer bills. Yet RGGI’s own announcement projects 20 billion dollars in future bill savings from investments, compared to allowance costs that, at current prices, could approach 30 billion dollars over a similar horizon if emissions remain near recent levels. Even if those bill savings materialize – a big if – they are not a free lunch; they are funded by the very bill surcharges the program imposes.

Moreover, the wholesale market cost adder described above means that a significant share of the burden falls on customers in the form of higher prices for every kilowatt‑hour, while benefits are concentrated in a subset of households and businesses that receive targeted efficiency or bill assistance. That might be a defensible redistribution if it were transparently acknowledged but calling the program an “affordability tool” obscures who pays and who gets paid.

RGGI states have long acknowledged leakage as a theoretical concern, but treated it as manageable. With Virginia’s reentry at current prices, leakage is no longer theoretical; it is inevitable, especially given the interconnected nature of PJM and the ability of non‑RGGI generators to serve load in RGGI states.[10][2][1]

Market Structure and Allowance Holdings Matter

Another blind spot in Acadia’s framing is how RGGI’s allowance market is structured and who holds allowances. Unlike some federal programs, RGGI does not publicly disclose ownership of allowances in detail; instead, its independent market monitor, Potomac Economics, reports aggregate holdings by broad categories such as “compliance‑oriented entities,” “investors with compliance obligations,” and “investors without compliance obligations.”

After Auction 72, compliance entities held 65 percent of allowances in circulation, and Potomac Economics estimates that 78 percent of allowances are held for compliance purposes. That leaves roughly 22 percent in the hands of entities that may be primarily motivated by investment returns rather than compliance.

There is also a fourth, largely unacknowledged category: non‑compliance entities that buy allowances explicitly to retire them, such as environmental organizations selling “carbon reduction certificates” to donors. While their holdings may be small today, the existence of such players underscores that not all allowances in circulation are actually available for resale or compliance.

In a tight market with a steeply declining cap, the presence of investors and voluntary retirement entities can exacerbate scarcity and volatility, driving up prices further. Acadia’s depiction of RGGI as a stable, well‑functioning market glosses over these structural issues.

Even RGGI States Now Admit There Is a Problem

Perhaps the most telling evidence that RGGI has drifted away from its original “no more than a few dollars per ton” promise is the RGGI states’ own recent language.

In the Auction 72 press release, the states tout the program’s benefits – emissions reductions, billions in proceeds, millions of households served – but then add a new note of concern: “Following this auction, the RGGI states intend to begin a scoping process to consider further targeted measures to continue to achieve reliable, clean electricity supply at affordable prices for consumers.”

Translation: at current prices and cap trajectories, the program is posing an affordability and reliability challenge serious enough to merit yet another multi‑year review process. This is the same program Acadia Center is selling to Virginians as an “energy affordability tool.”[3][2][1]

Given that the last program review, launched in late 2021, did not conclude until mid‑2025, there is a real risk that RGGI states will repeat the “slow walk” while allowance prices remain elevated and consumers bear the cost. If Virginia joins mid‑compliance‑period under these conditions, it will be volunteering its ratepayers to subsidize both regional climate ambitions and market participants’

Conclusion

The Acadia Report maintains that all is well with RGGI.  I believe that its conclusions are not supportable.  My analysis finds that RGGI now poses unacceptable affordability and reliability risks and needs immediate, fundamental revision.  The RGGI states must disavow this report and acknowledge the enormity of the risks and engage regulators, system operators, and state lawmakers to consider substantive changes rather than the incremental tinkering contemplated in recent RGGI communications. 

RGGI Quarter 2 2026 Auction Results

Updated after initial plublicatipn to include an Executive Summary and description of the RGGI announcement

In the last month I have published articles describing the impact of last year’s revisions to the Regional Greenhouse Gas Initiative (RGGI) and the impact of Virginia re-joining the program this year.  I noted that the cost of permits to emit CO2, aka allowances, increase when there is uncertainty or there is a scarcity of allowances. This post examines the results of the second quarterly auction of 2026 and concludes that the RGGI states must reconsider cost containment provisions and the projected trajectory for the cap on allowances.

Updated – Executive Summary

The second-quarter 2026 RGGI auction confirms that the program has become both an immediate affordability problem for consumers and a growing reliability risk. The allowance clearing price jumped 40% from $24.99 in March to $35.00 in June, and all available cost-containment reserve allowances for 2026 had already been exhausted by the prior auction. Using New York as a case study, the post shows that direct allowance purchases already cost consumers on the order of 700 million dollars per year at 2025 prices, rising to well over 1.1 billion dollars if the new 35‑dollar price persists. Once the wholesale market cost adder is included, the effective consumer burden plausibly reaches into the 1.8–3.2-billion-dollar range, much of which becomes windfall revenue for generators that do not themselves have RGGI obligations and does not come back to customers through any investment program.

The post argues that these rising costs are not matched by commensurate emissions or reliability benefits, and in fact sit on top of an allowance trajectory that is fundamentally incompatible with historical and expected emissions trends. The updated cap path reduces allowances by more than 10 percent of the 2025 budget each year from 2027 through 2033, despite the fact that the region has never sustained reductions of that magnitude and recent years have seen emissions rise with load growth. When banked allowances are accounted for, the analysis indicates that the system could effectively “run out” of allowances as early as the second quarter of 2032, forcing compliant units either to shut down or to operate out of compliance. At the same time, a review of RGGI investment reports suggests that auction proceeds are being deployed inefficiently: the implied cost per ton reduced is far above common social cost of carbon values, and RGGI-funded projects explain only a small fraction of observed reductions. The post concludes that the program now poses unacceptable affordability and reliability risks and needs immediate, fundamental revision—by regulators, system operators, and state lawmakers should reconsider participation —rather than the incremental tinkering contemplated in recent RGGI communications.

Author Background

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.

Background

RGGI is a market-based program to reduce greenhouse gas emissions from the power sector. It has been a cooperative effort among Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont since 2008, with New Jersey rejoining in 2020 and Virginia scheduled to rejoin beginning July 1, 2026; Pennsylvania recently decided not to join.

According to the RGGI program description, the states issue permits to emit a ton of CO₂ that are distributed almost entirely through regional auctions, and the proceeds are then reinvested in strategic energy and consumer programs. Those investments include energy efficiency, clean and renewable energy, beneficial electrification, greenhouse gas abatement and climate adaptation, and direct bill assistance, with energy efficiency receiving the largest share.

I have long had concerns about the RGGI program, but recent events have exacerbated potential impacts on affordability and reliability.  The event that solidified my belief that changes are in order was the fallout from the April 29, 2026 RGGI statement that Virginia was rejoining the program.  I explained  in the days that followed, the futures market price of RGGI allowances nearly doubled, and the spot market cost also increased significantly.  The closing price of the most recent RGGI auction on June 3, 2026, was $35.00 up $10 from the March 11, 2026 auction price of $24.99 (Figure 1).  This post describes the my concerns with this volatility.

Figure 1: RGGI Quarterly Auction Clearing Price

RGGI Affordability

RGGI allowance costs are driven by basic economic considerations. When there is scarcity, prices increase; when there is uncertainty about scarcity, costs also go up. The difference is that price increases associated with uncertainty can drop when more information is available, whereas as will be shown in the following, scarcity has been built into RGGI so costs may remain high going forward.

There are two consumer impacts of higher RGGI allowance prices.  Table 1 lists the annual proceeds from the RGGI auctions which in the last two years have totaled about $1.5 billion.  RGGI advocates claim these proceeds are invested in strategic energy and consumer programs.  In my review of the latest annual RGGI Investments of Proceeds report I concluded that RGGI does not make effective investments.  Claims that RGGI is a successful program are inconsistent with the following observations.  The overall RGGI cost per ton of CO2 reduced is $849.50 which is far above the social cost of carbon.  The amount raised falls far short of the funds necessary to reduce RGGI emissions in accordance with Third Program Review requirements.   Emission reductions associated with RGGI investments only account for 7.6% of the observed reductions.

In 2025 the direct cost of allowances in New York equals the annual emissions by multiplied by the average auction price: 32,037,339 tons times the annual allowance price or $22.09 per ton.  NYS consumers paid about $707.7 million for RGGI allowance costs assuming all allowances used came from the 2025 auctions.

Table 1:  Annual Auction Price and Proceeds

In a recent article I described the second consumer impact of RGGI allowance costs.  When generating units bid to sell their power in daily electricity market auctions, they include the cost to purchase replacement RGGI allowances.  If the clearing price is set by a unit that must comply with RGGI, then the added cost of RGGI allowances is included in their bid.  The problem for consumers is that every generating unit gets paid the clearing price.  That means facilities with no RGGI compliance obligations still get paid as if they did.  As a result, those facilities garner windfall profits at the public’s expense.

My analysis only looked at the effect of the RGGI electric market cost adder on New York State ratepayers.  I used annual values as a proxy for the hourly impacts that would ideally be calculated and summed across the year.  In 2025, statewide gross energy from New York RGGI units totaled 67,094.6 GWh, those units emitted 32,037,339 tons of CO2, the average quarterly RGGI auction price was $22.09 per ton, and NYISO Gold Book Table III-2a reports total net New York energy of 132,182 GWh.

Table 2 provides bounding estimates for the electric market effect for last year’s average allowance price and the clearing price of the Quarter 2, 2026 RGGI auction ($35).  The first section, “Cost of Allowances for Annual Emissions,” documents the direct allowance-cost numbers.  If the future RGGI allowance prices settle at the Quarter 2 2026 auction price, consumers will have to pay an additional $413.6 million for a total of $1.121 billion.  The remaining scenarios use observed heat rates and observed CO2 emission rates derived from EPA data to estimate an allowance-cost adder in dollars per MWh, which is then multiplied by total NYISO energy to estimate the statewide annual cost impact for the two allowance prices.  This bounds the likely costs to consumers.  I believe that RGGI-affected units normally set the clearing price.  If the price were set by a modern combined cycle gas turbine every hour at the average generation rate,  then the increase from last year’s average price to the last quarterly auction price then consumer costs would increase $680 million to a total of $1.8 billion.  I believe this is a lower bound.    Using the same assumptions but assuming the auction price is set by an old inefficient simple-cycle combustion turbine, consumer impacts increase $1.17 billion to $3.18 billion.

Table 2: Range of Impacts of RGGI Cost Adder on New York State Ratepayer Annual Costs

Also note that the windfall profits do not accrue just to New York generators.  All imported electricity delivered to New York is affected by RGGI costs. Imported electricity from outside New York has the same perverse outcome: embedded RGGI costs paid in the exporting state are included in the prices paid by New York consumers.  My analysis does not include these costs, so  I am underestimating the impact of RGGI costs.  This situation exists for all RGGI states.

RGGI Reliability

There is another RGGI issue that needs to be addressed.  RGGI advocates ignore the fundamental risk that RGGI-affected electric generating units will only operate if they possess allowances to comply with their RGGI obligations.  The RGGI states recently updated the allowance cap trajectory so it would be consistent with state laws that require emissions to go to zero.   As a result, the allowances allotted to the program decline by over 10 percent of the 2025 budget per year from 2027 through 2033.  The problem is that the historical emissions have never consistently shown reductions of that magnitude.

RGGI Emission Trends

Figure 2 plots CO₂ emissions by fuel type across all eleven states from 2006 to 2025.  What you see is fuel switching caused the reductions and that there are only minor opportunities for future fuel switching.  When I analyzed the 2023 RGGI investment proceeds report, I found that only about 7.6% of observed emission reductions could be attributed to RGGI‑funded projects despite RGGI auction proceeds of over $7 billion since 2021.  Changes to Federal policy, supply chain issues, and inflation coupled with load growth all indicate that reductions from other programs are unlikely as well. 

Figure 2: Eleven State RGGI CO₂ Emissions (short tons) for all Programs 2006–2025

Table 3 demonstrates that the cap trajectory is simply incompatible with reality. There have been four years with double digit percentage emission reductions and one of those occurred before RGGI started.  Because CO2 reductions are essentially equivalent to energy use, interannual variation can be caused by weather demand for energy.  Sustained emission reductions can occur because of control programs for other pollutants and economic fuel switching to low carbon fuel aka natural gas.  I think the 2008 10% reduction was affected by fuel switching and weather variations.  The first three years (2009-2011) of RGGI were characterized by increases and decreases that had nothing to do with RGGI.  The largest annual reduction since RGGI started in 2009 occurred in 2017 and was due to economic fuel switching.  The last double digit percentage reduction occurred in 2019.  Most importantly, emissions have increased due to load growth in the last two years.

Table 3: 11-State Clean Air Markets Division Emissions Data for All Regulatory Programs

When Will the Allowances Run Out?

Because the revised RGGI allowance reduction trajectory did not consider the emission trend I made an estimate of future allowance status using the data described above to determine when allowance availability would require units to shut down to comply.  Comparing the allowance allocations to the emissions does not consider the allowances already in the system.  The “allowance bank” is the aggregate number of allowances in circulation that have been issued but not yet surrendered for compliance (i.e., held in accounts or set‑asides). Historically there has been such a large bank of allowances the RGGI States implemented several adjustments to the allowances allocated to reduce the bank.  These adjustments ended in 2025.

RGGI does not provide a report that regularly describes the status of the allowance bank, so I had to develop my own estimate.  In my post When will the allowances run out? I documented the procedure I used to estimate quarterly emissions, allowance additions, and the resulting allowance bank status so I will not repeat that material here. 

Figure 3 plots the quarterly emissions (green), allowance cap (dark blue), added allowances (light blue) and allowance balance (orange).  This analysis assumes that emissions remain constant and shows that as the allowance cap is reduced the bank of allowances eventually is exhausted.  When the allowance balance is less than zero there are no longer sufficient permits to emit CO2 and affected units must shut down or end up out of compliance.  My analysis projects that this could happen as soon as Quarter 2 2032.

Figure 5:  Quarterly RGGI Allowance Balance, Emissions and Allowance Cap

RGGI Revisions are Necessary

In response on May 8, the RGGI states issued a notice that they were monitoring the allowance market in response to a sharp increase in the secondary futures market price.  The closing price of the June 3, 2026, quarterly auction shows that their concerns about allowance market prices are legitimate.

The RGGI allowance results announcement also described concerns:

Following this auction, the RGGI states intend to begin a scoping process to consider further targeted measures to continue to achieve reliable, clean electricity supply at affordable prices for consumers.  As part of that process, the RGGI states will offer opportunities to engage stakeholders for feedback on the range of topics to be considered and analyses that could be conducted, such as analyses related to ensuring RGGI’s continued benefits to residents, affordability to consumers, and the smooth reintegration of Virginia into the market.

The RGGI third program review process took years.  This stakeholder engagement needs to be done quickly and not on a protracted basis like that. Consumers are revolting against utility rate hikes under 10% and this 40% increase will add to those cost increases.  RGGI states needs to be accountable. 

Unfortunately, the RGGI states have not acknowledged two other cost problems.  RGGI states typically equate consumer costs to the auction prices.  The cost to consumers includes two other impacts.  RGGI-affected sources also purchase allowances on the secondary market and if the cost is higher than the auction purchase price consumers pay that cost and get no investment benefits.  There also are no investment benefits in most of the embedded cost of RGGI allowances in the electric market.  The RGGI cost adder is applied to all generators resulting in an enormous unacknowledged cost. 

Finally, RGGI must acknowledge that the expectation that the current allowance trajectory is incompatible with the reality of potential emission reductions.  I evaluated the emissions associated with the New York State Energy Plan Pathways Analysis scenarios.  Table 4 shows that none of the scenarios project emissions consistent with the NYS RGGI allowance cap trajectory.  This will inevitably force RGGI-affected sources to shut down to comply with RGGI creating an artificial energy shortage.

Table 4: Comparison of RGGI Proposed Part 242 Cap and State Energy Plan Pathways Analysis Electric Power Scenario Projections

Conclusion

RGGI must be revised.  The Quarter 2 auction price increase from the previous auction portends future increased allowance costs.  RGGI states have not acknowledged that the costs to consumers are greater than the funds available for investment benefits nor that the alleged benefit claims are weak, so this is affordability pain for no gain.  The allowance cap trajectory is simply incompatible with observed and likely generating resource development that can displace existing resources. RGGI is headed to the point where there are  insufficient allowances to enable sources to run and remain in compliance. This can no longer be ignored because if left unchecked this will lead to an artificial energy storage, 

Three groups must act.  Regulators should revise the RGGI regulations.  The Regional Transmission Operators that operate in RGGI states must revise their planning estimates to incorporate the allowance cap trajectories.  Politicians in RGGI states who are worried about energy affordability should seriously consider dropping out of the program because it is simply unaffordable and risky without major changes.

Guest Post: Would You Rather Live Near A Battery Energy Storage System or a Nuclear Plant  

This post was originally published at Watts Up With That

Earlier this year I assembled a post describing a white paper by Richard Ellenbogen  M.E.E. titled The Intrinsic Danger of Siting Utility Scale Lithium Based Energy Storage Systems In Densely Populated Areas.  In this post I summarize his New York State Public Service Filing An INES Type Scale to Rate Battery Energy Storage System (BESS) Incidents and a Comparison of 50 Years of US Nuclear Generating Plant Operation with the Past 2-1/2 Years of BESS Operation in the United States (“PSC Filing”).  I italicized Ellenbogen’s direct quotes in the rest of this post.

Ellenbogen is the President [BIO] of Allied Converters and frequently copies me on emails that address 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.

Ellenbogen’s Introduction

NY State has become the proverbial “Lady that Swallowed the Fly”, with the fly being state energy policy over the past several years that has led to the NYISO warning about blackouts and major generation shortages in the very near future. NY State’s solution, or cure for those years of failed policy, has been to swallow the entire barnyard and all of the animals in it without adequately reviewing the consequences of their actions. For those unfamiliar with the parable, the lady dies at the end.

This is a very ironic situation because over the past 37 years, NY State has decommissioned three functioning nuclear reactors, Shorham’s 820 MW in 1989 and Indian Point’s two reactors with a combined 2000 MW capacity between 2020 and 2021. All of the units were shuttered essentially because of public fear of the systems and the associated political pressure.

That makes comparing nuclear plant safety with BESS safety a valid comparison for utility system viability and that is what this document will explain in detail. As the comparisons will show, a nuclear plant is a statistically far safer facility to have located in any community than a BESS System. The nuclear industry is far more regulated and has far more stringent reporting requirements, and as a result over its entire history dating back 65 years, it has caused far less, if any, environmental damage than a BESS industry that is less than a couple of decades old. In spite of that, NY State seems determined to inflict damage on its local communities to try and mitigate the damage from its failed energy policies.

Methodology

Ellenbogen reviewed nuclear incidents rated by the International Nuclear and Radiological Event Scale (INES) since 1975 and then used Perplexity AI to determine if there was a similar BESS event scale.  Finding none he used Perplexity AI to develop a similar rating system and applied starting on January 1, 2024.  The next figure shows the INES scale and summarizes the different levels.

Ellenbogen submitted the following query to Perplexity AI to rate BESS incidents.

Build a comparison dashboard between the IAEA’s INES nuclear safety scale and the NFPA 855 Standard for Stationary Energy Storage Systems. Contrast their methods of categorizing risk, detailing how each approach measures hazard severity (INES uses radioactive release, NFPA 855 uses fire-suppression and containment metrics). Include a summary of how battery industry analysts actually classify ‘thermal runaway’ events compared to nuclear ‘accident’ levels 4–7, and synthesize current industry frameworks for reporting site-level battery fires and containment failures into a structured, side-by-side positioning report

Ellenbogen Results

As is documented in the PSC Filing Appendix 3, the response was that there has only been one Level 4 INES event in the past 50 years and that was 47 years ago. The only other event, referenced as SL-1, occurred in 1961 and that was not a commercial nuclear plant. It was an experimental military reactor built when the nuclear industry was in its infancy.

Table 1 summarizes the eight Level 2 and higher events that have occurred at US nuclear plants since 1975. Radiation release was only associated with the Level 5 event at Three Mile Island and after 46 years, there have been no deaths associated with that event and no environmental damage.  There was one level 3 event in 2002, 24 years ago, and six level 2 events with the latest being 16 years ago. That was related to an electrical fire in switchgear and not to the reactor. That type of fire also occurs in utility substations and goes unnoticed unless it turns the night sky blue over NY City. No radiation release was associated with the seven Level 2 and Level 3 incidents and there was no local impact from any of them.

Table 1: INES Level 2+ at US Nuclear Generating Plants Since 1975

As a comparison to the nuclear safety record documented above are the ten BESS incidents that have

occurred in the United States during a period of 2-1/2 years since January 1, 2024, one twentieth of the

timeframe of the nuclear analysis and one sixth of the timeframe since the last Level 2 or higher nuclear

incident.

Figure 3 lists the ten incidents based upon the INES/BESS rating system created by Perplexity. There

have been two Stage 4 events with major discharge of gases and heavy metals, four Stage 3 events and

Four Stage 2 events. Note that two of the Stage 3 events were the newer LFP technology, and the

description associated with them is “Better Contained”, not “Fully Contained.” Additionally, “Better” is a

very relative term when the bar has been set so low by prior events. Also note the comment about the

reporting vacuum regarding sub-ignition events. Contrasted with over 50 years of nuclear plant operation with no environmental damage, the record of Lithium based BESS systems over 1/20th the timeframe with significant environmental damage is abysmal. This is all fully documents in the PSC Filing  Appendix 2.

Figure 3: Battery Incidents at US Utility Scale Energy Storage Facilities Since 1/1/2024           

Ellenbogen Implications

Ellenbogen also asked Perplexity: If battery fires release gases and heavy metals, how does that compare to a Level 2 nuclear generator incident that has no radiation release?

His submittal included the following Perplexity response:

BESS Fire Emissions vs. Level 2 Nuclear Plant Incident: What’s Actually Released This is one of the most analytically uncomfortable asymmetries in the entire framework. The short answer: a Level 2 nuclear plant incident releases nothing into the environment by definition, while a Stage 2–4 BESS fire releases a chemically complex, multi-pathway hazardous plume that would trigger federal reporting requirements under almost any other industrial sector.

In the prior statement, Perplexity was stating that the Stages in its BESS Scale don’t correlate on an

“Apples to Apples” equivalent with the INES Scale because a Level 2 Nuclear Event is far less impactful

on the surrounding environment than its determination of a Stage 2 BESS Event. The effects of that and

the chemicals released are documented in Appendix 4 and echo what was presented in my previous filling.

While the newer LFP BESS systems are better, they are not foolproof and they are not as benign as the

installers would have you believe.

Further, the statement that a Stage 2–4 BESS fire releases a chemically complex, multi-pathway hazardous plume that would trigger federal reporting requirements under almost any other industrial sector, is indicative of the fact that not clearly documenting these events has the “ignorance is bliss” effect on both the public and policy makers.

Ellenbogen noted that Perplexity also had the following suggestion regarding Policy Implications for Grid Scale Deployment of BESS Systems:

As utility-scale BESS Installations grow to multi-GWh scale in locations like New York, California, and Texas – often sited in or near dense grid interconnection zones – the absence of a standardized, post event severity classification system creates an analytic blind spot. The nuclear sector’s INES framework, for all its limitations, enables regulators to benchmark the severity of events across time and geographies. An equivalent BESS classification standard – one that integrates EUCAR cell-level data, UL 9540A propagation outcomes, and EPRI root cause taxonomy into a unified, publicly reportable Severity number – would represent a significant advancement in grid-level energy storage risk management.

That type of framework does not exist and based upon the lack of information available to the public and

their representatives, decisions about these systems are being made in an information vacuum where the only stimulus is BESS money being dangled in front of the noses of towns without any attention being

paid to the potential downstream consequences. To understand the full ramifications of this information

gap, readers are encouraged to read the full incident histories of the ten events that are documented in

PSc Filing Appendix 5. The event history with consequences and evacuations starts on page 35 and the entirety of Appendix 5 was constructed without human intervention or prejudices.

Ellenbogen Conclusion

The BESS Industry has a far worse safety and environmental record over the past 2-1/2 years than the

nuclear industry has over the past 50 years, a period twenty times as long. NY State regulators and policy makers are ignoring these facts and allowing these systems to be installed in populated neighborhoods while also ignoring the potential consequences. The fact that the BESS industry is immune from regulations that would “trigger federal reporting requirements under almost any other industrial sector “, clearly documents how far the state and the industry has to go before allowing widespread installations of these systems. Regulators are not ensuring the public’s safety. They are only trying to put a band-aid on years of utility system mismanagement.

The following unsolicited conclusion generated by Perplexity documents the problem far better than any human could.. While the IAEA would not be the regulating agency for BESS Systems, the Department of Energy could be.

The Regulatory Gap in One Number

The 6 nuclear plant Level 2 events (1996–2010) all involved zero radiation release — pure defense-in-depth degradation. Every one triggered mandatory NRC notification, IAEA submission, and public INES rating. The BESS equivalent — a BMS anomaly, suppression margin reduction, or near-ignition precursor — has no federal reporting pathway, no IAEA submission, and no public rating requirement. That asymmetry is the structural argument Section 07 of the dashboard documents in real incident terms.

The Level 2 nuclear comparison doesn’t show that nuclear is more dangerous than BESS. It shows the opposite problem: the nuclear framework is so mature it captures events that cause zero harm, while the battery framework misses events that cause documented, measurable, multi-pathway environmental harm.

Based upon the prior information, the question has to be asked, “From a public safety standpoint, if you’ve decommissioned three nuclear reactors, why would you want to install a BESS facility in populated areas that is far less safe?”

Guest Post – Heat Pump Rate Carveouts

It has been my experience that every aspect of the green energy transition is more complicated than it appears at first.  This is an example of the unintended consequences of a transition component.  I recently met Scott Endler who provided this guest post describing a proposal to change the electric rate structure to support heat pumps.  The proposed solution is not what it seems.

Scott is a self taught efficiency and energy analyst in Central New York.

I acknowledge the use of Perplexity AI to convert Endler’s study into this post.

Background

On May 5, 2026, “A coalition of environmental groups today filed a petition calling on the New York Public Service Commission to fix electric rate designs that unfairly overcharge households that switch to clean electric heating. The petition was filed by Alliance for a Green Economy, Building Decarbonization Coalition, Earthjustice, Environmental Defense Fund, New Yorkers for Clean Power, Rewiring America, and Sierra Club”. 

The basis for the petition is a report conducted by Switchbox, “Heat Pump Rates in New York State: An Analysis of Cost-Based and Cost-Reflective Rates for Heat Pump Customers.” The report claims that when customers switch from gas heating to heat pumps they dramatically cut their energy use, however, most of these same customers see their bills go up due to outdated electric pricing policies. My initial impression is that if cost savings are only possible by changing policies then the proposed “solution” is not all it is cracked up to be.  Endler explains why this is more complicated below.

Why heat pump carve‑outs are a dead‑end

Advocates like Earthjustice and Switchbox argue that New York utilities are overcharging heat pump customers for delivery service—on the order of hundreds of dollars per year—and propose a dedicated “heat pump rate” to fix the problem. Their basic case rests on two current facts about the New York grid.

  • The system is still summer‑peaking, so much of the winter distribution network is treated as “already paid for,” with plenty of headroom when heat pumps run on cold but not extreme days.
  • A customer who electrifies heat can see roughly a doubling of their kWh volume, so volumetric delivery charges go up even if the utility’s embedded winter distribution costs barely move.

From there, the coalition jumps to a political conclusion: create a boutique, technology‑specific discount so heat pump adopters pay less for winter delivery while everyone else stays on the old schedule. That might satisfy the coalition in this rate case, but it fails three basic tests: fairness, durability, and alignment with the Climate Leadership & Community Protection Act (CLCPA) long‑term grid trajectory.

The transition paradox: today’s spare winter capacity won’t last

The core problem with the carve‑out logic is that it freezes today’s grid snapshot and pretends it is permanent. CLCPA‑driven electrification of buildings and transportation all but guarantees that New York will flip from a summer‑peaking to a winter‑peaking system sometime in the 2030s, as electric heat and winter peak EV charging push load into the coldest hours.

Under that future paradigm, heat pumps are no longer opportunistic users of “free” winter capacity; they become the main driver of localized peak demand, transformer overloads, and the next round of capital projects. The very customers who are being framed today as victims of an unfair delivery rate will, in a decade or so, be the marginal cost causers when the system is strained on sub‑zero January mornings.

Designing a permanent special discount for a technology that is on track to become the dominant driver of winter peaks is a textbook example of a policy that works only as long as it doesn’t succeed.

Horizontal equity: same wires, same rules

If the wires are a shared public asset, then any consumer who pushes current through those wires at a constrained hour should face the same price signal regardless of what device is on the other end of the cord. I frame this as “horizontal equity”: identical structural rules for every ratepayer.

In a horizontal‑equity framework, a kilowatt‑hour is charged based on the physical state of the network and the prevailing supply price, not on whether it feeds a heat pump, a resistance heater, an EV, or a Bitcoin rig. That approach avoids cross‑subsidies from non‑adopters to relatively affluent early adopters of new technologies, a regressive pattern that is already visible in some rooftop solar and EV incentives.

By contrast, a bespoke “heat pump” class asks a single mom in a gas‑heated apartment to pay higher delivery charges so that a homeowner with a brand‑new variable‑speed HP and smart thermostat can enjoy a tailored discount in the name of climate justice.

A dynamic, capacity‑based delivery price

The counter‑proposal coming out of the feasibility study is a dynamic, capacity‑based delivery tariff that works much more like the wholesale energy market. Instead of a static cents‑per‑kWh delivery rate smeared over all hours, the distribution price would move up and down with remaining localized grid capacity.

  • When local transformers, feeders, and substation capacity are plentiful—say, on a quiet winter night—the marginal cost of using the network is low and the delivery price falls toward zero for everyone.
  • When capacity is tight—say, during a frigid morning when Winter Storm Fern pushed downstate resources to the brink—the delivery component spikes exactly when the system is most stressed.

This preserves cost‑recovery for the utilities over the year while sending a sharp, physics‑based price signal in the hours when grid use is genuinely expensive. Crucially, the signal is identical for any customer whose load shows up in that hour.

Why this beats Straight Fixed‑Variable (SFV)

Some utility economists default to Straight Fixed‑Variable designs—high fixed monthly charges and very low volumetric delivery rates—to stabilize revenue as electrification reshapes load. The problem is that SFV guts the conservation signal: once you’ve paid your hefty monthly fee, each extra kilowatt‑hour costs very little, so the customer’s incentive to invest in efficiency or to shift load out of peak hours is weak.

A capacity‑prorated volumetric charge keeps the usage‑based signal intact. Customers still save real money by using less energy over the billing period, and they get an additional incentive to avoid precisely those hours when both supply and wires are constrained. That is exactly what CLCPA‑era demand management is supposed to reward.

In other words, this is a way to modernize rate design without flattening everything into a subscription fee that severs the link between behavior and system cost.

Behavioral and planning benefits

Under a dynamic distribution price, a heat pump owner is not punished for having electrified; they are only penalized if they insist on running at full load in the same hour that everyone else is trying to do the same thing on a constrained circuit. The rational response is not to rip out the heat pump, but to invest in insulation, envelope upgrades, and smarter controls that quietly shave load exactly when the grid is tight.

This architecture also makes grid planning more honest. When the delivery price spikes repeatedly on a certain circuit, it is a market signal that the wires and transformers there are under‑sized relative to demand, justifying targeted capital upgrades instead of generalized rate hikes. Because every technology sees that same price shape, the planner’s data isn’t distorted by carve‑outs and exemptions.

You can think of it as bringing distributed marginal‑cost pricing down from the wholesale level into the distribution system, instead of trying to fine‑tune social policy via ever more fragmented rate classes.

How this plays out as CLCPA bites

Look at the CLCPA trajectory and the recent Winter Storm Fern emergency order for a preview of the stakes. As more load is pushed into winter mornings and evenings, the occasional near‑miss we saw in January 2026 becomes more common unless billions are poured into wires and flexible resources.

In a world of boutique heat pump discounts, those marginal infrastructure costs get socialized onto everyone else while the prime driver of the peak enjoys a protected class rate. In a capacity‑based, technology‑neutral regime, the households and businesses that draw power at the worst times pay the highest delivery price, regardless of whether they are doing the “right thing” in some broader climate narrative.

That may be politically uncomfortable, but it is honest—and if CLCPA is supposed to be about aligning economic signals with physical reality, it is hard to justify anything else.

Where advocates are right—and what regulators should do instead

The Earthjustice coalition is not wrong to say that current volumetric delivery tariffs can make early electrifiers look like suckers. But the fix should address the structural flaw in the rate design, not just the optics for one favored technology.

Regulators who genuinely care about affordability and equity should focus on:

  • Deploying interval‑capable meters fast enough to make capacity‑based delivery pricing administratively feasible.
  • Phasing in a simple, transparent distribution price that reflects localized capacity conditions, starting with the most constrained circuits.
  • Avoiding the temptation to endorse technology‑specific carve‑outs that will be impossible to unwind once the political beneficiaries are numerous and vocal.

That path doesn’t lend itself to a press release about “fixing heat pump delivery rates,” but it would actually modernize the tariff architecture for a high‑electrification, high‑constraint grid.

Conclusion

New York’s new “heat pump rates” campaign gets one thing right: today’s delivery tariffs are a blunt instrument that can punish electrification. But carving out a special rate class for heat pumps is the wrong fix; a capacity‑based, technology‑neutral delivery charge tied to real‑time grid conditions would be fairer, more durable, and far more honest about who actually drives system costs.

New York State Renewable Permitting Scandal

This article was also posted at Watts Up With That

Paraphrasing the Washington Post “Environmental Protections Die in Darkness”, could be a slogan for New York’s Climate Leadership & Community Protection Act (CLCPA) monomaniacal emphasis on renewable energy development.  Reasonable limits have never been established on wind and solar projects, so developers have been given free rein to build wherever is most convenient and cheap without regard to the environment.  If a recent article in the New York Post is any indication, however, that may be changing.  I explain the context of solar development in New York in this article.

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.  I have followed the Climate Act since it was first proposed, submitted comments on the Climate Act implementation plan, and have written over 600 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

Background

The CLCPA has been an exercise in political pandering to emotion-driven activists convinced that climate change is an existential threat that can be solved by transitioning to an energy system reliant on wind, solar, and energy storage.  I have been writing for years about the lack of a feasibility analysis that demonstrates that relying on renewable energy that does not provide energy all the time, including the times when needed the most, does not work well in New York’s climate and high latitude, and relies on resources that tend to fail at the same time over large areas. Instead of an ordered approach to decarbonization, New York lawmakers enacted a transition plan that consists of building as much wind and solar as possible, as fast as possible, and assumed that it would all work out. 

In the first year after the CLCPA was enacted renewable development did not get permitted as fast as the developers and activists wanted.  In April 2020, New York lawmakers enacted the Accelerated Renewable Energy Growth and Community Benefit Act that created the Office of Renewable Energy Siting (ORES) to implement a consolidated, expedited siting and permitting process for major renewable energy facilities.  Because New York progressive lawmakers know everything, the idea that there should be conditions on development was not included in the law.  There was no provision to ask the Department of Agriculture and Markets for recommendations on limits for the taking of prime farmland.  The Public Service Commission was not asked if solar developers should have technology mandates like tilting axis solar panels or recommendations not to build solar facilities in the Great Lake snowbelts that get 20 feet of snow a year.   The Department of Health did not establish noise limits to protect industrial neighbors of wind turbines.  In every instance there have been egregious impacts that the ORES permitting process has ignored as they rubber stamped approvals despite the strenuous efforts of local groups concerned with those impacts.  In future articles I will address these impacts.

The more I learn about the permitting process the more I am convinced that most New Yorkers have no clue about these destructive policies.  The local grassroots organizations have been knee-capped by this law and have failed to kill projects that cause what I am sure state agencies would agree are unacceptable impacts.  Publicity is needed to expose this scandal. The grassroots organizations opposed to unfettered renewable development that has no safeguards usually count themselves lucky to get a mention in a local newspaper or TV station, but their reach is limited.  They have not been able to get this issue publicized enough.

There is another egregious impact. I have no doubts that if the lawmakers had asked the Department of Environmental Conservation to recommend limits on destruction of rare and endangered species habitat, they would certainly have demanded limits on fragmenting habitat.  That did not happen and it has come to the attention of a social media influencer who is articulate, passionate and mad.  She also has a platform.

Alexandra Fasulo

Alexandra Fasulo has a Substack called House of Green with the stated goal “to equip you with the information and stories you need to farm, garden, homestead, futurestead, set up agricultural education businesses, and heal the environment.”   Her overall Substack presence (including House of Green and other titles) is listed as having “53K+ subscribers” and ranked around #13 in the Climate & Environment category.  Her Youtube channel has 384K subscribers and videos routinely get tens of thousands of views.  In her latest endeavor she established  a farm and her followers can monitor her homestead progress. 

When she found out about the nearby planned 100 MW Fort Edward Solar Project she attended a public hearing.  It was a wakeup call.  I think her public reach as social media influencer is going to have an impact as exemplified by the fact that the New York Post reached out to her.  She gave him the overview and connected him with other people in the article.

Fort Edward Solar

Chadwick Moore’s article describes Fasulo’s initial reaction to the Fort Edard Solar Project at a public hearing:

“There was nearly unanimous opposition to this project. So, I thought it wouldn’t go through. That’s how representative democracy works, right? Wrong.”

I had the same reaction about this project.  As shown in the following map that was used in the article, the project is within the Audubon-designated Fort Edward Grasslands Important Bird Area and the NYNHP Raptor Winter Concentration Area.  It also surrounds the NYS DEC Grassland Wildlife Management Area on three sides.  Note that the developer frequently points out that their project does not surround the Wildlife Management Area on all sides. The idea that fields of solar panels could be permitted adjacent to a wildlife management area is beyond my comprehension.

The Fort Edwards site, in red, is in the middle of a state-recognized wildlife sanctuary.

Grassland Bird Trust/ American Land Rescue Fund

I admire Fasulo because she did not take the rejection of her concerns sitting down.  She established a non-profit American Land Rescue Fund to “defend America’s land through law and action.”  Because the permitting documents are heavily redacted, she hired independent consultants to assess the environmental impact.

That report, reviewed by The Post, shows the Fort Edwards site sits inside a NYS Department of Environmental Conservation-managed grassland and bird sanctuary “well known for high species diversity of breeding grassland birds and important numbers of wintering raptors including an Endangered and a Threatened species,” the report stated.

The species impacted by the development include the endangered short-eared owl (fewer than 50 breeding pairs remain in the state, per the Grassland Bird Trust), the threatened northern harrier and 15 species of reptiles and amphibians of “conservation concern,” among many others.

Moore goes on to describe 17 other solar projects in Upstate New York that have their own issues. 

Each of the 18 sites ORES has selected will have a capacity over 25 megawatts. The agency also has an additional dozen wind projects in the works.

Some of the largest projects are the 4,000-acre (6.25-square-mile), 500-megawatt Cider Solar Farm in Genesee County and the 2,000-acre (3.1-square-mile) Ridge View Solar Farm in Niagara County, as shown on The Post’s map.

To add insult to injury, many of the multibillion-dollar solar contracts have been farmed out to foreign companies — including Canada’s Boralex, France’s EDF Renewables, and South Korea’s Cypress Creek Renewables, The Post has found. 

He describes a smaller project in Copake NY. 

A hundred miles south in the bucolic Hudson Valley town of Copake, local resident Sara Traberman has made fighting Big Solar her full-time job. Chicago-based developer Hecate Energy scooped up over 700 acres of productive farmland to install a planned 42-megawatt-capacity solar facility, expected to go online late next year.

Locals were told to expect two years of nonstop construction where 547 dump trucks and 10 pile drivers along with numerous cranes and excavators will swarm the picturesque hamlet from 7 a.m. to 8 p.m. — seven days a week.

“It’s about changing the character of this town. It’s a rural, farming community. We just ask that the rules of the town and the view of what the people want for where they live is respected,” Traberman told The Post.

“It’s going to impact tourism, local traffic, the schools. It’s going to be horrible.

Moore also describes a lawsuit against ORES in Montgomery County. 

Developers were permitted to gobble up 6,400 acres (10 square miles) — most of it active farmland — for two massive solar complexes near the towns of Canajoharie and Root.

Montgomery County Attorney Meghan Manion told The Post the litigation challenges “the grossly unlawful actions of ORES,” which “deviated from lawful procedure by choosing not to follow their own regulations in granting these [solar] permits.”

While developers cover the cost of construction, locals have to eat revenue losses on property tax for the sites, Montgomery County lawmaker Michael Muhlebeck told The Post. He also said his constituents, who are “97 percent” opposed to the projects, will likely face higher utility costs due to the increased demand that often follows large industrial projects like this.

Issues

The article describes the futility of changing the climate with solar power and explains that solar resources in New York are not strong.  According to the New York Independent System Operator summary of renewable performance utility-scale solar facilities provided between 16 and 19% of the maximum possible generation over the last four years.   There is a bigger problem.  Electric resource planning must be based on the worst-case event.  During last winter’s extreme winter weather 18-day episode the daily solar capacity available was less than 10% half the time and less than 5% three days.  I also showed that this episode proves that in these events all short-term energy storage would be depleted early, leaving insufficient renewable generation to both meet demand and recharge storage systems. As a result, a new dispatchable emissions-free resource is needed to keep the lights on.

I recommend checking out the article’s map of the 18 solar projects currently under consideration by ORES that extend from far western New York to the Canadian border in the north.  All these projects are needed to provide New York City with zero-emissions electricity as part of the CLCPA.  Because they are so spread-out transmission upgrades will undoubtedly be required, if not for these projects, then surely for all the other renewable projects necessary.

The experiences recounted in the article indicate that unfettered renewable energy development in New York is causing demonstrable environmental impacts.  Given environmental advocacy outrage over environmental impacts of data centers it is disappointing that they have not expressed their concerns over the more extensive impacts of renewable energy development.

At the end of the day this outcome is solely on the lawmakers who supported these laws.  They never enabled state agencies to fulfill their missions, and I think you could say they prevented them from doing so in the process.  The developers cannot be faulted for taking advantage of the situation and ORES staff is simply following the law.  Prior to 2019, the state agencies would have said the environmental impacts f Fort Edward Solar are unacceptable and asked the developer to build their facility somewhere with less impacts.

Conclusion

Montgomery County lawmaker Michael Muhlebeck summed up the scandal:

“New York state has taken more and more from our communities and they’ve literally just shut us down. We no longer have the right to protect our residents.  “But there’s a goal that has to be met. And that goal is bigger than our local communities, our wildlife, our wetlands. And they don’t care,” she added.

Publicity is needed to expose this scandal. I hope that the power of social media exemplified by Alexandra Fasulo can bring this to the attention of enough New Yorkers that the policies can be changed to protect the environment and interests of the local communities impacted by these industrial developments.  The only way this can be fixed is for legislative change.