Author: rogercaiazza

I am a meteorologist (BS and MS degrees), was certified as a consulting meteorologist and have worked in the air quality industry for over 40 years. I author two blogs. Environmental staff in any industry have to be pragmatic balancing risks and benefits and (https://pragmaticenvironmentalistofnewyork.blog/) reflects that outlook. The second blog addresses the New York State Reforming the Energy Vision initiative (https://reformingtheenergyvisioninconvenienttruths.wordpress.com). Any of my comments on the web or posts on my blogs are my opinion only. In no way do they reflect the position of any of my past employers or any company I was associated with.

Implications of the New York Approval of RGGI Amendments

On August 5, 2026, the New York State Department of Environmental Conservation (DEC) approved amendments to Part 242 CO2 Budget Trading Program.  This makes New York regulations consistent with the RGGI Third Program Review Model Rule but I believe that it was short-sighted because significant changes that occurred since the rule was proposed were ignored.  Furthermore, DEC has yet again failed to address the impacts of the rule on New Yorkers which are described in this article.

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

Background

RGGI is a market-based program to reduce greenhouse gas emissions (GHG) (Factsheet). It has been a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector since 2008. New Jersey was in at the beginning, dropped out for years, and re-joined in 2020. Virginia joined in 2021, withdrew in 2024, and rejoined effective July 1, 2026, and Pennsylvania considered joining but has since decided not to join.

RGGI includes a provision for regular reviews. The Third Program Review was completed in July 2025. It strengthened the regional CO₂ emissions cap through 2037, with steeper reductions from 2027 to 2033 and a lower rate thereafter. New York was required to align their regulations with the updated Model Rule by January 1, 2027, and finalized their rules to meet that requirement as mentioned earlier.

New York Benefits of RGGI Claim

RGGI is essentially a cap-and-invest program.  On a quarterly basis the RGGI states auction allowances or permits to emit a ton of CO2.  Proponents of this strategy tout the investment of the proceeds of the auctions as the  primary benefit to consumers.  The New York State Energy Research & Development Authority (NYSERDA) designed and implemented a process to develop and annually update an Operating Plan which summarizes and describes the initiatives to be supported by RGGI auction proceeds.  I usually comment on the annual updates.  For example, this year I commented and summarized the final 2026 Operating Plan.

The press release announcing that the regulations were finalized states:

The adopted RGGI program updates will help ensure New Yorkers continue to enjoy cleaner air while creating jobs and boosting the economy. The amended regulations build upon the progress already achieved by RGGI, including reducing carbon dioxide emissions from New York’s power sector by 50% from 2005 levels and generating more than $3 billion in RGGI auction proceeds that support investments in energy efficiency, renewable energy, and electrification that ultimately provide savings to utility ratepayers

My primary concern is that RGGI is an electric sector emissions reduction program and that state policies do not appreciate that.  The press release says that the observed carbon dioxide emissions reductions in New York’s power sector of 50% from 2005 levels are part of “the progress already achieved by RGGI”.  In the first place RGGI did not start until 2009 so the observed 24% reduction in emissions between 2005 and 2008 are not due to RGGI.  I believe it is more appropriate to compare emissions to three baseline years before RGGI started (Figure 1).  This figure shows that there was an emissions peak in 2005, and I calculate that when using the 3-year baseline  New York power sector emissions are only down 33%.  Furthermore, as shown in Figure 1, the primary reason for the observed reduction is due to fuel switching from coal and oil to natural gas.  I believe that the fuel price differential for natural gas use was much greater than the added cost of RGGI allowances in the early years, so the main driver of the observed reductions was economic fuel switching.   Also note that the option for fuel switching is not available anymore.

Figure 1: New York State Emissions by Fuel Type

The revisions to DEC RGGI regulations reduce the allowances available but it is not clear where the future reductions will come from.  Therefore, I believe that programs that materially decrease electric sector emissions directly or indirectly through energy use reductions should be a priority because affected sources have no other compliance options. I argued in my comments on the Operating Plan amendment that there are programs in the amendment that do not meet these criteria.  I think it is only appropriate to fund the non-priority programs if sufficient funding has been allocated to make the emission reductions necessary to meet RGGI compliance mandates. 

Affordability

According to the DEC the financial implications of RGGI are positive.  DEC and NYSERDA’s press release announcing finalization of these amendments claims that RGGI investments in New York have generated nearly $12 billion in net ratepayer savings over the lifetime of the program’s investments, on roughly $2 billion invested to date – a “nearly 6-to-1” return. In addition, the response to Comment 9 in the DEC Assessment of Public Comments claims that RGGI reduces consumer costs:

The proposed amendments are designed to deliver affordable energy. The RGGI Program has been shown to reduce the electricity bills of New Yorkers through the investments of proceeds raised by the RGGI Program. The updates to the RGGI Program, as outlined in the RGGI bills analysis , are estimated to have no significant impact on utility bills, with a slight decrease compared to status quo even under pessimistic projections of renewable energy deployment.

This section shows that those claims are incorrect.

The claim that there is a “nearly 6-to-1” return on investments is derived from NYSERDA’s June 2026 RGGI funding-status report—but the description simplifies important qualifications.  The underlying report does not call the $12.334 billion figure “net ratepayer savings.” It calls it “Energy Bill Savings to Participating Customers.” It is a modeled, expected-lifetime estimate that includes savings attributed to projects still in the pipeline—projects under contract or with applications received but not yet operational. NYSERDA also states that the metrics are estimates and generally have not been adjusted through evaluation, measurement, and verification.

The claimed return also compares lifetime projected participant bill savings with historical funds expended, rather than comparing verified realized savings with the full cost of the RGGI portfolio. The report notes that benefits may be recorded before associated funds are financially reported and that some reported project benefits reflect joint support from other NYSERDA non-RGGI funding sources. Those caveats mean the 5.6-to-1 calculation should not be read as a verified, RGGI-only net benefit to all New York ratepayers.

The “nearly 6-to-1” calculation also compares this projected lifetime benefit stream against $2.188 billion in historical expenditures. That is not an audited return on investment or a demonstration of savings to all New York ratepayers. The report further acknowledges timing differences between benefit reporting and financial reporting, as well as projects supported jointly with other NYSERDA funding sources.

More importantly, NYSERDA’s own recent EmPower evaluation demonstrates why the headline should be treated cautiously. It found evaluated-to-estimated realization rates of only 20% for natural-gas savings and 18% for electric savings. NYSERDA attributes part of the discrepancy to a methodological shift that increased estimated savings; it also reports declining evaluated electric savings over time and identifies cases where repairs increased energy use because previously non-functioning equipment could again be used. These findings do not mean the programs provide no customer benefits, but they do mean that modeled lifetime bill savings should not be marketed as verified “net ratepayer savings.”

In addition to the failed premises of the benefits, the cost estimates are incomplete because they primarily considered just the auction allowance costs.   The June 2025 Analysis Group presentation cited to claim that RGGI has “no significant impact on utility bills”. concludes that the RGGI Third Program Review update would have only small effects on average electric bills—generally within about ±1 percent—and that reinvesting auction proceeds could further reduce bill impacts. The analysis compares the proposed RGGI program update with a “status quo” case based on the volume-weighted average allowance price from the twelve most recent auctions. It considers two clean-energy deployment cases and three proceeds-reinvestment scenarios.[

The presentation should not, however, be interpreted as an estimate of the total cost of RGGI to New York electricity customers. It is an incremental comparison between two RGGI policy cases: an updated program and a baseline that already includes RGGI allowance costs. Therefore, its small bill impacts indicate only that the model projects relatively small differences between the update and its chosen RGGI status-quo reference case.  Importantly, it does not include the 40% increase in allowance prices noted in June 2026.

Analysis Group states that ICF modeled “wholesale electricity prices and allowance proceeds,” so it would be inaccurate to claim that the study wholly ignores wholesale-price effects that I think that RGGI advocates do not acknowledge. But the brief presentation does not explain how the wholesale-market model handles the critical mechanism by which allowance prices affect consumer costs. It provides no detail on whether generator offers reflect current allowance opportunity costs, which units set marginal prices, or whether the model quantifies the resulting uplift in market-clearing prices paid to all dispatched resources.

That omission is significant in New York’s marginal-price electric market. When an emitting generator is needed to meet load, its RGGI allowance obligation is incorporated into its offer price. If that generator is marginal, the allowance-cost adder can raise the clearing price received by every accepted generator in the affected market interval—not merely reimburse the emitting generator for allowances purchased. Lower-emitting, non-emitting, and even imported resources may receive the higher clearing price despite having little or no corresponding RGGI compliance cost.

The direct cost of allowances and the wholesale market-clearing effect are therefore different things. Earlier this year I showed New York RGGI-unit allowance expenditures in 2025 at roughly $708 million using 32.0 million tons of emissions and an average $22.09 per-ton auction price. But it estimates that applying plausible marginal-unit allowance adders across statewide electricity consumption could add total annual consumer impacts of roughly $1.16 billion to $2.26 billion, depending on the assumed marginal generating-unit characteristics. Those figures are bounding estimates rather than a substitute for a full NYISO hourly production-cost and market-settlement analysis.

Discussion

There is a fundamental affordability issue raised by a colleague who wishes to remain anonymous.  He makes a point about the RGGI cost-recycling model that I have not seen made as clearly anywhere else in the record. As he put it:

This is all about time value of money. We take more dollars from the consumer – funnel to government administered programs on a time delay and realize some time delayed energy efficiency gains coupled with limited bill credits for certain customers. The end result is more consumers fall over the cliff into the limited bill credit programs.

Take one dollar today and give you 20 cents back in a year from now with everyone else subject to the poorly administered government programs with high admin fees. The original dollar gets watered down to a low percentage of value.

Conclusion

The approval of the RGGI amendments does not address the reality of emission reduction requirements and affordability.  New York CO2 emissions from the electric sector have leveled off and the only way for further reductions is to displace fossil units with zero emissions resources.  At a time when Hochul acknowledges the realities of “the COVID-19 pandemic and supply chain interruptions, inflation, the Trump administration’s hostility to wind and solar projects and ongoing trade wars” have made the Climate Act timelines “less possible” it is risky to not prioritize RGGI funding on proven emission reduction programs.  If there are insufficient allowances available it will create an artifical energy shortage preceeded by allowance price hikes.

RGGI revenues run through a state-administered efficiency or bill-credit program, and returned as a fraction of its original value months later is not the same as a dollar left in that ratepayer’s pocket today. Discount the delayed, partial, administratively-diminished return to present value and the “6-to-1” return DEC advertises looks a great deal less generous than the headline number suggests. And that is before accounting for the fact, which I have documented in prior posts, that a large share of the embedded RGGI cost in electricity bills – the cost adder created when RGGI-obligated generators bid their allowance costs into the wholesale market – never gets captured by any investment program in the first place. It just flows through to consumer bills as cost, full stop, with no delayed benefit on the other end at all.

I conclude that New York has not acknowledged that RGGI has entered a new phase where reality can no longer be ignored.

RGGI’s Market Monitor Confirms the Scarcity I’ve Been Tracking

Recently I explained why I thought DEC’s New York State’s Short-Sighted Approval of Regional Greenhouse Gas Initiative (RGGI) Amendments ignored developments that undercut the analytical basis for the rule it finalized. Potomac Economics, the RGGI market monitor, has now published its Report on the Supply and Demand for RGGI CO2 Allowances: Second Quarter 2026, and it is worth a close look because it simultaneously confirms nearly everything I have documented about the RGGI allowance market this year and demonstrates exactly the blind spot that let DEC finalize Part 242 without confronting it. This post explains why I think the report is both a vindication of my reporting and, through what it deliberately does not say, more evidence that DEC’s rulemaking record was out of date when promulgated.

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

Background

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

As part of its oversight role, RGGI, Inc. retains Potomac Economics as the independent market monitor for the CO2 allowance market. On August 21, 2026, RGGI, Inc. released a special report from Potomac Economics, the Report on the Supply and Demand for RGGI CO2 Allowances, which it described as intended to help compliance entities “easily access key metrics” as they prepare to meet their obligations for the sixth control period (CP6), which closes March 1, 2027. This is not a periodic publication.   RGGI, Inc. has never produced a report like it before, unlike Potomac Economics’ quarterly Secondary Market Report, which was released the same day as a routine, recurring product. The timing is hard to read as coincidental. It arrives roughly three and a half months after RGGI, Inc. issued a public statement on May 8, 2026 acknowledging “high allowance prices and recent volatility” in the secondary market and pledging to watch future auction results before considering program adjustments. Whatever the stated purpose, this is the closest thing to an official accounting of “how many allowances are left” that RGGI has ever produced.  I think it is the document that New York State will leans on when anyone asserts that the allowance bank will probably be sufficient to cushion consumers from near-term cost impacts.

Timeline

In 2026 the price of allowances has been higher and more volatile than anytime since the start of the program. The allowance clearing price jumped from $24.99 in the March 11, 2026 auction to $35.00 in the June 3, 2026 auction, a 40% increase, with all of 2026’s Cost Containment Reserve (CCR) allowances already exhausted by the March auction. In between, on May 8, 2026, RGGI, Inc. issued a public statement acknowledging “high allowance prices and recent volatility” in the secondary market and said it would watch upcoming auction results before considering any program adjustments — the first sign RGGI itself was paying attention to the scarcity narrative building around its program. On May 15, 2026, I published my own allowance-bank exhaustion estimate, built from Potomac’s Q4 2025 secondary-market data because RGGI does not regularly provide its own accounting of the bank’s status, and projected the bank going negative around Q3 2032 to Q3 2033. Virginia formally rejoined RGGI on July 1, 2026. On August 5, 2026, DEC and NYSERDA jointly announced they had finalized the Part 242 and Part 507 amendments, effective January 1, 2027, over the objections I described in my August 19 post. On August 21, 2026, RGGI, Inc. released Potomac Economics’ special Q2 2026 Supply and Demand report alongside its routine Q2 2026 Secondary Market Report, giving us, for the first time since the rule was finalized — and for the first time ever, in the case of the Supply and Demand report — an independent, data-driven look at exactly the allowance-bank question DEC’s response to comments treated as settled.

What the Report Confirms — and Conveniently Doesn’t Say

RGGI frames the report as a routine compliance aid, but the timing tells a different story. The August 21 announcement describes the Supply and Demand report only as a special report “intended to help compliance entities easily access key metrics” as Control Period 6 winds down, with no reference anywhere to the $35 auction, the exhausted CCR, or the market commentary treating the June price jump as evidence of scarcity. But this is the first report of its kind RGGI has ever produced, and it lands eleven weeks after that record auction and three and a half months after RGGI’s own May 8 statement acknowledging “high allowance prices and recent volatility.” An organization that had never felt the need to publish a standalone supply-and-demand accounting despite my comments arguing that it was necessary suddenly produced one, unprompted, in the same window it was publicly fielding questions about whether the market was running short. RGGI is entitled to describe its own motives, but a “compliance aid” framing that omits any mention of the price spike that plausibly prompted the report in the first place is itself a data point about how this program manages its own narrative.

The report confirms what I documented in real time about the Cost Containment Reserve running dry. I reported that all of 2026’s CCR allowances were gone by the March 11 auction. The Q2 2026 report independently reaches the same conclusion, stating that “given recent allowance price levels, all remaining CCR allowances are assumed to be sold in Auction 73”.  The market monitor is now modeling full CCR exhaustion for the rest of the control period even when the Virginia CCR allotment is included in the next action. That is not a hypothetical anymore; it is the market monitor’s own baseline assumption, and it means the “release valve” DEC’s response to comments points to when it needs to reassure people about price spikes has already been used up, months before the compliance deadline crunch even arrives.

The market itself is behaving exactly as my scarcity argument predicted, even while the headline number says “surplus.” The report puts the Control Period 6 allowance surplus at 55 million tons (61% of the 2026 cap) as of the end of Q2 2026, down from 71 million tons at the end of CP5, and projects it will fall further to 45 million tons by the March 1, 2027 compliance deadline. Read in isolation, that sounds comfortable. But the report also shows that the composition of that surplus has shifted hard: investor-held allowances fell from 60 million tons at Q2 2025 to 37 million tons (68% of the surplus) at Q2 2026, while compliance-held allowances rose to 18 million tons (32%). The report attributes this to entities holding onto allowances for their own future compliance needs instead of releasing them into the secondary market, along with a rise in traders “spreading” 2026-vintage futures against 2027-vintage futures to hedge post-2026 exposure without tying up scarce near-term allowances. In plain terms, the people who actually have allowances to sell are increasingly choosing not to sell them. A surplus that will not come to market behaves like scarcity, which is exactly why the price jumped 40% in a single quarter while the official surplus number still looked fine.

Virginia’s return adds less new supply than the demand it brings with it. The report quantifies what I could only describe qualitatively in my May 9 and June 16 posts: Virginia’s re-entry adds 12.6 million allowances, including CCR, across the two remaining 2026 auctions, against 17 million tons of covered emissions Virginia generated in the second half of 2025 alone. A state that shows up with a 4.4-million-ton gap between the allowances it brings and the emissions it is already producing is not a source of relief for the regional bank; it is a net new claim on it.

The report authors twice flag their emission projections as too high. The Q2 2026 report notes that its assumption for second-half 2026 emissions “may be a conservative assumption because it does not account for the impact of recent allowance price increases” suggesting that higher prices could suppress emissions.  This theory is an article of faith for RGGI advocates but is flawed in my opinion.  Many other factors impact electricity generation emissions including unit performance, major transmission outages, abnormal weather, fuel pricing, and electric demand in the short term.  In the long-term patterns of electric production, electrification, and large load growth affect demand and emissions which are inextricably connected.   I believe that these inelastic factors outweigh allowance price impacts on emissions such that higher allowance prices just mean more consumer costs.

Given my pre-retirement responsibility tracking RGGI allowance compliance holdings relative to emissions I want to highlight the following claim in the report:  “A substantial share of the allowance surplus is held for compliance purposes – The number of surplus allowances held for compliance purposes was 18M (or 32 percent of the surplus) at the end of the second quarter.”  The report goes on to say “The compliance entities that hold these surplus allowances have generally not made them available for sale in the secondary market in the past, presumably intending to use them for compliance in the next control period.”  There has always been a disconnect between compliance entities and the academic theory of market programs like RGGI.  The theory is that compliance entities consider opportunities to make money in the secondary market, but the reality is that the compliance risk of insufficient allowance trumps that option.  If they do not have the allowances, then they will not run so the fact that only 32% of the surplus is held for compliance is concerning.  Also consider that means that 68% of the surplus is held by investors.  Presumably those investors want to maximize their profits so I think that means it is unlikely that costs will allowance prices will drop significantly because the surplus margins are small.

Most importantly, the report explicitly refuses to say anything about the exact question DEC needed an answer to before finalizing Part 242. The Q2 2026 report states plainly that “analysis of these factors” — meaning the post-2027 cap trajectory and the implications of the Third and now-needed Fourth Program Review — “is beyond the scope of this report.” That is an honest disclosure by Potomac Economics about what its report does and does not cover. But it also means the projected allowance surplus says  nothing about the annual cap cuts of more than 10% of the 2025 budget that begin in 2027 and run through 2033;  That is an entirely different order of scarcity than the roughly 2-million-ton annual declines this report is describing for 2023 through 2026. My own allowance-bank model, using the steeper post-Third-Program-Review cap, projects the bank going negative by 2032 or 2033 — a conclusion this report cannot confirm or refute because it was never designed to look that far ahead. Treating a Control Period 6-scoped market-monitor report as evidence that the post-2027 cap trajectory is manageable, which is functionally what DEC’s response to comments does, is exactly the kind of error the report’s own scope disclaimer should have prevented.

Bottom Line

RGGI, Inc. will not say this report exists because of the $35 auction and the scarcity questions that followed it, but the timing makes the connection hard to dismiss. Potomac Economics did its job. Its Q2 2026 report is a careful, appropriately hedged accounting of the sixth control period’s allowance bank, and it independently confirms nearly every specific claim I have made in my reporting this year: the 2026 CCR allowances are gone, the market is hoarding rather than releasing allowances as the compliance deadline nears, Virginia’s return brings more emissions than allowances, and the market monitor’s own baseline assumptions may understate how tight things really are. The failure here is not the market monitor’s. It is DEC’s. DEC and NYSERDA finalized Part 242 on August 5 leaning on “the Cost Containment Reserve” and “the allowance bank” as reasons consumer impacts would be manageable, without ever grappling with the fact that the only rigorous, independent accounting of that bank explicitly declines to say anything about the post-2027 period the amendments actually govern. A report that says “the near-term bank is fine, but we are not going to tell you anything about the long-term bank” is not evidence that the long-term bank is fine. DEC should stop citing the allowance bank as a reassurance it has not earned, and it should push for an immediate start to the Fourth Program Review rather than letting the “no later than 2028” timeline it floated in its response to comments run out the clock on a cap trajectory that its own market monitor will not vouch for.

New York Energy Policy BESS Disconnect

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

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

The Problem

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

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

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

Battery Requirements

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

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

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

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

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

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

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

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

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

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

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

Alternatives

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

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

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

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

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

Practical Scenario

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

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

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

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

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

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

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

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

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

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

Conclusion:

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

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

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

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

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

Background

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

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

Timeline

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

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

Factors not Considered

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

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

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

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

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

Bottom Line

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

How Neighboring Electric Systems  Handled the July 2026 Heat Wave

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

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

Overview

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

PJM: The Most Acute Stress in the Country

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

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

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

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

ISO New England: Tight, But Wind Actually Helped

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

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

MISO: High Load, Weak Wind, No Emergency

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

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

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

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

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

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

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

Comparing the Regions

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

Conclusion

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

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

Ellenbogen’s Data From the July 2026 Heat Wave

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

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

Overview

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

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

Voltage and Frequency at the Ellenbogen Factory

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

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

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

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

Source: Data provided by Rich Ellenbogen

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

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

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

The July 2–4 Event at the Factory

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

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

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

Source: Data provided by Rich Ellenbogen

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

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

Source: Data provided by Rich Ellenbogen

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

Source: Data provided by Rich Ellenbogen

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

Con Edison System Voltage on July 3

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

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

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

Source: Data provided by Rich Ellenbogen

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

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

Source: Data provided by Rich Ellenbogen

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

Source: Data provided by Rich Ellenbogen

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

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

Home Solar Inverter Fault Log

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

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

Broader Consequences

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

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

Conclusion

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

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

My Affordability Presentation at Stop Energy Sprawl Connect Across the Lines Conference

Update: My presentation is available on Youtube

On August 8, 2026 I gave an affordability presentation at the Stop Energy Sprawl Conference “Connect Across the Lines”.  This post documents my presentation as promised to the attendees. Although it just provides bullet points with links others may find it useful as a summary of my Climate Leadership & Community Protection Act (Climate Act) affordability concerns.

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 risks, unacceptable costs, and adverse environmental impacts.  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

Stop Energy Sprawl is a coalition of  community groups, municipalities, and elected officials from localities in New York State targeted by land-wasting, large-scale wind and solar projects located far from where that energy is needed. This year’s conference, aims to inform on the affordability, legality, feasibility, and community impacts of New York’s energy policies. 

The post reproduces the slides with references included.  I acknowledge the use of Perplexity AI to find and summarize my articles documenting this presentation.  I used Perplexity AI to prepare a list of links to my articles related to specific topics that I linked to my web site. Those links are labeled as (Perplexity AI Summary).

Introduction

Affordability Presentation Topics

  • Climate Leadership & Community Protection Act (CLCPA or Climate Act) energy transition
  • “Cheap” renewables myth
  • Affordability Messaging in State plans
  • Ratepayer Impacts per Kris Martin

Climate Act Premise

Source: Climate Act Scoping Plan

  •  Public Service Law § 66-p
    • Public Service Law 66-p (Perplexity AI Summary) Implications
    • Section 66-p (4) includes an affordability safety valve if “there is a significant increase in arrears or service disconnections that the commission determines is related to the program”.
    • PSC may “temporarily suspend or modify the obligations” of the CLCPA after conducting a hearing
    • Two petitions requested that the PSC address this
    • On 1/28/2026 the PSC asked for comments
    • Comment deadline was the end of April
    • No action taken yet
  • There is No Clear CLCPA Affordability Limit –  No references needed
    • CLCPA does not define acceptable consumer cost impacts
    • Without a clear affordability boundary, there is no real cost constraint.
    • That makes affordability a political slogan instead of a measurable requirement.

Source: Adapted from figure by Charles Rotter at Watts Up With That

  • But What About Cheap Renewables? (Perplexity AI Summary)
    • Energy storage
    • Transmission Upgrades
    • Backup generation
    • Grid ancillary support
    • Dispatchable, firm generating resources

These issues are addressed in a subsequent presentation.

  • Cheap Renewables – Only Half the Story
    • The “cheap renewables claim usually refers to low project-level Levelized Cost of Energy (LCOE), not total system cost.
    • LCOE measures the cost of producing electricity when available, not the cost of running a reliable grid.
    • Consumers pay for a full electric system, not just low-cost megawatt-hours.
    • The grid must work on the worst day of the year – high load low, renewables
    • Cheap electricity is not the same as dependable electricity.

Source: NYISO 2025-2044 System and Resource Outlook Appendix J: Renewable Generation Pockets

  • Hidden Cost – Transmission (Perplexity AI Summary)
    • Large-scale renewable development requires major transmission upgrades to move power from Upstate to New York City and Long Island
    • Simple project-level cost claim do not include interconnection and grid reinforcement costs
    • Consumers ultimately pay for wires, substations, and congestion relief through rates.
  • Hidden Cost – Reliability Backup (Perplexity AI Summary)
    • A weather-dependent grid still needs firm resources for cold, snowy, dark, and low-wind periods.
    • Short-duration batteries can help with ramps and short peaks, but not long-duration system stress.
    • Long-duration periods require special resources that are not commercially available at this time so costs are unknown.  This is the Dispatchable Emissions Free Resource (DEFR) technology
  • Hidden Cost: Electrification (Perplexity AI Summary)
    • Affordability impacts extend beyond utility bills to building conversions, appliance replacement, and vehicle transition costs.
    • Households face upfront capital costs even before any promised fuel savings appear.
    • Low- and middle-income customers are least able to absorb these transition costs.
    • A true affordability review should count economy-wide household energy burdens, not just electric rates.

Another Way to Look at “Cheap” Myth

  • Weather-dependent electric grid needs four systems for reliable power per Scott Grout
    • Base wind and solar fleet
    • Battery system for diurnal and short-term backup
    • Additional wind and solar to power the battery systems
    • Dispatchable firm resources during the doldrums
  • Each system makes for a larger, more complex, and more expensive electric grid.

Source: Healthy Skeptic “Energy Subsidies”

If renewables are so cheap why do they need subsidies?

  • Kevin Roche argues that the total taxpayer subsidy per energy produced shows that renewable wind and solar require subsidies

Source of Graph: Scoping Plan Chapter 10: Benefits of the Plan

Scoping Plan Affordability

State Energy Plan Affordability

  • State Energy Plan Affordability (Perplexity AI Summary)
    • The energy affordability analysis in the Energy Plan shows that “the use of new, efficient equipment and electrification can cut energy spending by $100 to over $300 every month for many New York households, across energy costs for transportation and heating and utility bills.”

Source: NYS Energy Planning Board Meeting Presentation Slide 40

  • State Energy Plan Affordability Claim

I developed this figure to summarize the changes needed to electrify households

Source: NYS Energy Planning Board Meeting Presentation Slide 43

Source: NYS Energy Planning Board Meeting Presentation Slide 43

  • Bottom Line Climate Act Household Cost
    • Difference between Conventional and High Efficient is cost of CLCPA
    • $1,968 minus $1,374 or $594 per month (43%)

Feasibility Warnings

  • State Agencies Feasibility Warnings and Affordability (Perplexity AI Summary)
    • State reviews have acknowledged inflation, supply chain problems, permitting barriers, siting opposition, and interconnection delays.
    • The State Energy Plan indicates current deployment trajectories are not sufficient to meet statutory ambitions.
    • Feasibility problems increase affordability risk because delay almost always increases cost.

Direct Ratepayer Costs

Ratepayer Costs – What is Included

  • Renewable projects are supported through Renewable Energy Credits (RECs) and Offshore wind Renewable Energy Credits (ORECs) purchased by NYSERDA and passed through to utilities.
  • Zero Emission Credits (ZECs) support nuclear plants undermined by renewable subsidies
  • Utilities recover those costs from customers through electric bills.
  • Climate Act charges also include related items such as EV incentives and transmission upgrades that are buried in utility bills.
  • Commercial and industrial customers face even higher Climate Act bill percentages than residential customers.

Source: NYS DPS Second CLCPA Informational Report on Overall Implementation of the CLCPA

  • Current Bill Impacts Look Smaller Than They Really Are
    • The PSC says Climate Act costs are still a small portion of the typical residential bill.
    • That is true only because the forecasts include contracted Tier 1 projects awarded through 2024, not the much larger future buildout needed to meet the law’s targets.
    • In other words, today’s bill impacts reflect only part of the program cost.
    • The larger REC and OREC obligations are still ahead.
  • Charges Reflect an Incomplete Buildout
    • Kris Martin notes that the 2029 forecast includes existing and already-contracted capacity, but not the additional capacity still needed for the 2030 renewable mandate.
    • Those omitted resources represent considerable added cost.
    • If Climate Act costs remain “modest,” that is evidence that buildout is falling short, not that the transition is cheap.
    • Ratepayers will eventually be asked to fund the missing capacity if the mandates stay in place
  • REC Costs Could Rise Sharply
    • At roughly similar REC pricing, wind and solar generation growth from about 6.5 million MWh in 2024 to more than 63 million MWh in 2030 would raise REC costs from about $220.9 million to above $2.1 billion.
  • Affordability Key Findings
    • Climate Act “affordability” is a political slogan
    • “Cheap” renewables is a myth
    • Affordability messaging in state plans is misleading at best
    • Ratepayer impacts are significant and will get worse
  • Affordability Recommendations
    • Define affordable
    • Do not mandate technology
    • Do not mandate a schedule
    • Do not try to go to zero – lower is good enough
    • NYS GHG emissions are less than one half of one percent of global emissions
    • Global emissions have been increasing more than one half of one per cent per year for decades

Conclusion

New York should replace inflexible Climate Act mandates with an affordability-first, technology-neutral strategy that delivers practical emissions reductions without imposing costs on ratepayers that are disproportionate to the State’s limited influence on global emissions

NYISO’s New Resource Outlook – Affordability Implications

The New York Independent System Operator (NYISO) released its 2025-2044 System & Resource Outlook (Outlook on July 22, 2026.  The report is framed as a reliability and resource planning document — not an affordability study — but the cost implications buried in its findings are hard to miss. NYISO never uses the word “affordability” as a headline, but the numbers do the talking. Here’s what jumped out at me, and why I think it validates concerns I’ve been raising for years about the Climate Act’s implementation trajectory and associated costs.

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 risks, unacceptable costs, and adverse environmental impacts.  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 an initial draft of this article. 

Background

The NYISO is responsible for electric resource planning for New York State.  The Comprehensive System Planning Process (CSPP) consists of four components: the Local Transmission Planning Process (LTPP), the Reliability Planning Process (RPP), the Economic Planning Process, and the Public Policy Transmission Planning Process. I discussed this process in my earlier article about the Outlook.  On August 3, 2026 the NYISO hosted a public information briefing on the document and the slide presentation gives a good overview.

Capacity Needed for Full Zero-Emissions

The Outlook evaluates 20 scenarios (up from just five in the prior 2023-2042 Outlook), varying demand growth, resource availability, and policy stringency. I think the most striking finding is that futures requiring a 100% zero-emissions grid by 2044 require roughly 105 GW of new resources under higher demand conditions, compared to just 30-60 GW for “policy-relaxed” futures that allow continued operation of repowered and new dispatchable fossil generation. Scenarios with no clean energy targets at all land at just 10-35 GW.

For context, New York has added less than 15 GW of new resources to the entire system in the last 25 years. NYISO is telling us, in its own understated way, that the full Climate Act pathway demands a buildout of a scale this state has never attempted — and that relaxing the emissions target by even a modest amount cuts the required build by two to three times.

That is not a subtle distinction. Every gigawatt of new capacity must be paid for by somebody, and in New York that somebody is ratepayers. When NYISO says policy design “significantly impacts scale of new resource development,” what they’re really saying is policy design significantly impacts your electric bill.

Hydrogen: The Expensive Bet NYISO Wants to Avoid

Here’s a detail that deserves more attention than it’s getting. The place holder Dispatchable Emissions Free Resource (DEFR) necessary to keep the lights on during extended periods of low renewable resource availability in the Scoping Plan was hydrogen-fueled generation.  In the fully zero-emissions scenarios, NYISO’s modeling leans on up to 30 GW of hydrogen-fueled generation to provide firm capacity during peak periods — capacity that renewables can’t reliably deliver on their own. The catch: hydrogen-based generation “is not currently available at commercial scale and would require significant investment in infrastructure for fuel production, storage, and transportation, which does not exist today.” It’s the only technology in the entire study that isn’t commercially available now.

Dark doldrums are a significant challenge for a wind and solar dependent electric system but are rare.  NYISO’s report notes hydrogen would be expected to run infrequently, at low utilization, because of high operating costs. So we’re talking about building tens of gigawatts of a generation type that’s unproven, expensive to fuel, and would sit mostly idle waiting for the infrequent periods when it is actually needed. Policy-relaxed pathways eliminate this requirement entirely by letting existing and repowered fossil units continue providing that same firm capacity function. This is about as clean an illustration as you’ll find of the tradeoff between chasing a zero-emissions label and containing costs.

Downstate Ratepayers Are Already Feeling the Squeeze

Figure 8 in the report — “Tightened Supply Conditions Drive Higher Downstate Load Payments” — is the closest thing in this document to a real affordability chart, even though NYISO doesn’t call it that. Under the Contract Case (which assumes only currently-committed resources come online, with no additional buildout), modeled load payments in New York City and Long Island climb sharply between 2030 and 2044, dramatically outpacing every other zone in the state. The report’s own explanation: as generator retirements outpace new firm capacity, downstate load centers become increasingly reliant on imports and “higher-cost resources,” and NYISO explicitly ties this to “increased energy prices.”

Outlook Figure 8: Tightened Supply Conditions Drive Higher Downstate Load Payments

Source: 2025-2044 System & Resource Outlook

This isn’t a hypothetical far-future problem, either. The report states system conditions could become “increasingly susceptible to constrained conditions as early as the mid-2030s” — well within a decade. Note that the costs increase in every region, but if you’re a downstate ratepayer, the Outlook is telling you that the bill for current state energy policy starts arriving in less than ten years. 

Even Current Commitments Aren’t Enough

Maybe the most sobering line in the whole report: “Current resource commitments alone, even assuming all resources that have been awarded Renewable Energy Credit (REC) contracts come into service, are insufficient to meet future system needs over the Outlook horizon.” Read that again. Even in the best case where every renewable energy credit contract signed to date actually gets built on time — which, given New York’s track record of delayed offshore wind and slowed renewable development that this same report acknowledges, is itself optimistic — the system still falls short of what’s needed. That’s before you even get to the question of whether ratepayers can absorb the cost of closing that gap.

The report also quietly concedes that under Higher Demand conditions, the Climate Act-aligned scenario does not achieve the 9 GW offshore wind target by 2035 or the 70% renewable-by-2033 requirement, citing real-world constraints reflected in NYSERDA’s own Large-Scale Renewables Supply Curve. I’ve written about this gap between statutory targets and physical/economic reality before — it’s good to see NYISO’s modeling now says so explicitly.

Transmission Fixes: The Cheap Insurance Policy

To its credit, NYISO does flag some lower-cost opportunities that any policymaker serious about affordability should prioritize. Chief among them: targeted dynamic voltage support upgrades at the Central East interface, which constrains the flow of power from upstate generation to downstate load. NYISO frames this as a way to “increase transfer capability and better utilize existing infrastructure” — bureaucratic language for “get more out of the wires we already have instead of building new ones.” Similarly, bulk transmission upgrades in Northern New York are recommended to prevent curtailment of low-cost renewable output that would otherwise get stranded behind transmission constraints — power that ratepayers already paid to develop but can’t use.

These are the kind of targeted, relatively low-capital investments that should be the easy, no-regrets wins in any planning conversation. Compare that to the cost of building 30 GW of hydrogen infrastructure from scratch, and the contrast couldn’t be sharper.

Discussion

Strip away NYISO’s carefully neutral “objective, fact-based planning insights” framing, and here’s what the 2025-2044 Outlook is actually telling New York’s policymakers:

  • The stringency of the zero-emissions mandate is the single biggest cost lever available. Relaxing it, even partially, cuts required new capacity by two to three times.
  • Betting on hydrogen to fill the capacity gap is a bet on an unproven, expensive technology — and one that policy-relaxed pathways don’t need to make at all.
  • Downstate ratepayers are on track for materially higher costs starting as soon as the mid-2030s, driven by tightening supply and increased reliance on higher-cost generation.
  • Even full delivery on today’s contracted renewable projects won’t be enough, meaning more spending is coming no matter what.
  • The cheapest wins are transmission fixes, not new generation — squeezing more capacity out of existing infrastructure at Central East and unlocking stranded renewable output in Northern New York.

Conclusion

I have long wished that the “independent” NYISO would be more explicit in its analyses about the dangers of political interference in the electric system. They are not in the business of telling Albany politicians what New York climate policy should be, but when their numbers show that the most ambitious version of the Climate Act costs two to three times more in new infrastructure, relies on a technology that doesn’t commercially exist, and hits all New Yorkers with rising bills especially Downstate with its already high prices within the decade — that’s a set of facts policymakers ignore at their own, and ratepayers’, peril.

Implications of the NYISO 2025-2044 System & Resource Outlook

The New York Independent System Operator (NYISO) has released its 2025-2044 System & Resource Outlook (Outlook).  It’s a long-term planning assessment that finds New York will need “substantial new investment in reliable generation and transmission infrastructure to serve growing electricity demand and state policy targets.”  The report supports my contention that the rapid electric system transition to a zero‑emissions grid mandated by New York politicians is technically and institutionally constrained, and that reliability can be put at risk if policy timelines outrun feasible infrastructure and resource development.

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 risks, unacceptable costs, and adverse environmental impacts.  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

The NYISO is responsible for electric resource planning for New York State.  The Comprehensive System Planning Process (CSPP) consists of four components: the Local Transmission Planning Process (LTPP), the Reliability Planning Process (RPP), the Economic Planning Process, and the Public Policy Transmission Planning Process. My particular interest is the RPP.

Last December a NYISO update on the CSPP described the Reliability Planning Process.  It is a two‑year process that starts in even years and has two components. The Reliability Needs Assessment (RNA) “evaluates the adequacy and security of the Bulk Power Transmission Facilities (BPTF)

over a seven-year Study Period (years four through ten of the next ten years) and identifies Reliability Needs defined as violations of Reliability Criteria” established by regulatory authorities.  The second component is the System & Resource Outlook that is developed in the years between RNA.s  It includes the following:

  • 20-year study of system and congestion
  • Identifies, ranks, and groups congested elements
  • Assesses the potential benefits of addressing the identified congestion
  • Provides information to developers and marketplace regarding future challenges in the New York power system

The current analysis covers 2025 to 2044, so it must consider the transition requirements of the Climate Act.  NYISO’s long‑term scenarios show that reaching very high levels of zero‑emissions generation is a serious challenge.  This post is an overview of the Outlook emphasizing key insights and recommendations.

NYISO Summary and Key Findings

The press release provides a good overview of the Outlook.

The Outlook is a scenario-based planning study intended to help policymakers, regulators, market participants, and developers understand how different policy choices can shape New York’s future resource mix, transmission needs, system costs, and reliability risks over the next 20 years.

Key findings from the Outlook include:

  • New York’s electricity demand is expected to grow over the next two decades, driven by electrification and emerging large loads that increase total energy needs and reshape when and where demand occurs.
  • All scenarios require significant new generation, and policy-driven scenarios require far more installed capacity than exists today to reliably meet demand.
  • Transmission capability is increasingly central to system performance, public policy achievement, congestion reduction, and the ability of new resources to serve consumers.
  • The Outlook also shows that the final increments of emissions reductions carry the greatest infrastructure challenges. Scenarios that move from 95 percent to 100 percent emissions-free electricity require substantially more investment in replacement resources and anticipate technologies not yet available at commercial scale. By comparison, other scenarios that also lower emissions significantly do so with much lesser investment in generation and transmission.

These analyses compare alternate projections of policy mandates against a business as usual or base case.  NYISO describes the modeling scenarios:

The Outlook is structured around three groups of scenarios that represent the various futures evaluated in the Outlook. The Base Case is a reference future that aligns with the NYISO’s Reliability Planning Process assumptions1 to define the load, generation, and transmission assumptions. The Contract Case builds on the Base Case by adding generation projects with financial commitments (e.g., NYSERDA and offshore wind REC contracts) and approved transmission projects, as well as incorporating projected fossil retirements, to evaluate near-term system conditions as renewables come online and aging thermal units exit. The Policy Case, which includes eighteen scenarios, reflects relevant state policy targets by modeling pathways to meet (existing or delayed) targets like 70% renewables and 100% zero-emissions electricity and evaluates alternative resource mixes—including potential new nuclear and/or fossil—to assess progress toward policy achievement and resulting system conditions.

The Outlook selects two core policy scenarios for detailed production‑cost analysis: one “Higher” pathway that reaches a fully zero‑emissions grid by 2044 and one “Baseline/Policy‑limited” pathway that only achieves roughly mid‑90s percent zero‑emissions by 2044.

Resource Planning

My primary Climate Act implementation concern is the disconnect between the naïve presumption of Climate Act authors that the zero emissions electric system transition was only a matter of political will because the technical, logistical, and economic challenges were small and the reality that those challenges are enormous.  I do concede that at the time the Climate Act was written there was no expectation of significant load growth but that is only one aspect of the problem  The Outlook outlines the real challenges and the approach:

Meeting New York’s future electricity needs will require a significant transformation of the generation fleet, driven by rising demand, evolving policy requirements, and the retirement of existing fossil generation. As conditions evolve, ensuring that sufficient energy and capacity resources are available to serve load becomes increasingly complex. In particular, tradeoffs emerge between the pace, scale, and timing of new resource development, the types of resources available, and the ability of those resources to meet both energy needs and firm capacity requirements across the system.

To explore these dynamics, the Outlook evaluates a range of potential resource pathways that reflect differing assumptions about policy achievement, development pace, and system conditions. These scenarios are not intended to predict a single outcome but rather to illustrate how different combinations of demand, policy, and resource availability can produce materially different system outcomes—and to highlight the implications of those differences for future grid planning.

NYISO explicitly uses alternative futures (including “Higher Demand” and scenarios with advanced nuclear) to highlight that different combinations of resources can hit similar CO₂ outcomes but with very different reliability and feasibility profiles. That is an important distinction.  The statute and agency rhetoric treat “100% zero emissions” as a single, deterministic path in their plans.  In practice resource mix and infrastructure choices matter enormously.

Resource adequacy and reliability risk

The Outlook focuses heavily on resource adequacy through 2044 and shows that preserving reliability under Climate Act‑consistent trajectories depends on how quickly firm capacity is replaced as fossil units retire. NYISO’s analysis indicates that without sufficient dispatchable zero‑emissions resources and/or substantial new nuclear or long‑duration storage, the system faces tighter margins and greater risk, especially under higher load or stressed conditions.

NYISO also examines scenarios where demand is higher and weather or electrification trends deviate from planning baselines, and under those cases the resource and infrastructure requirements to keep reliability within criteria become much more challenging. A long‑standing theme of this blog is that “electrify everything” plus aggressive fossil retirements is a reliability problem, not merely an emissions accounting problem.  Electric systems must be built around reliability during peak demand.  One of my primary concerns with the Climate Act renewable energy mandates is weather variability because the conditions that characterize the highest loads also have the weakest expected wind resource availability.  The Hochul Administration’s planning has emphasized central forecasts and has yet to grapple with the specific challenges associated with extreme cases.

Limits of “100% zero emissions” portfolios

The document notes that alternate scenarios can achieve CO₂ reductions comparable to “100% zero emissions” portfolios while using different mixes of nuclear, storage, and renewables. NYISO explicitly discusses an “Alternate” path and advanced nuclear build‑out with up to 5 GW, limited to Zones A, B, C, and E (Figure 1) as ways to provide firm, clean capacity that ease system stress compared to strictly constrained portfolios.

Figure 1: NYISO New York Control Area Load Zones

Source: NYISO 2025-2044 System & Resource Outlook

Those scenario results essentially validate my arguments that insisting on specific technologies (or excluding others) is a policy choice layered on top of the emissions objective, and that some technology‑constrained paths are significantly more brittle from a reliability and cost perspective. The Outlook’s willingness to model advanced nuclear as a serious resource option contrasts with the Climate Act mandate and lends technical credibility to my arguments about the need for firm zero‑emissions capacity beyond intermittent renewables.

The Outlook finds that “policy design significantly impacts the scale of new resource development”.  For example. “Outlook scenarios without clean energy targets require approximately ~10–35 GW, scenarios with relaxed or partial zero-emissions scenarios require ~30–60 GW, and scenarios targeting a fully zero-emissions system require substantially higher additions— approaching ~105 GW of new resources by 2044 under higher demand conditions.  The difference in costs for all the new resources necessary for zero emissions versus costs for the relaxed emission scenarios relative to the differences in emissions should be an energy policy discussion point.  Furthermore, relaxed emission scenarios eliminate the need for developing hydrogen-fueled generation capacity and infrastructure development that the Outlook estimates at upwards of 30 GW.

Infrastructure, siting, and transmission constraints

NYISO’s long‑range analysis implicitly underscores how much new transmission and bulk infrastructure is required to move large quantities of upstate renewable and nuclear output to downstate loads, and to integrate storage at scale. The scenarios with substantial new nuclear and renewables in upstate zones make clear that geography, siting limits, and zonal restrictions are binding constraints, not footnotes.

By identifying zonal limits NYISO is effectively quantifying some of the siting and societal impacts that disproportionately impact Upstate New York. The Outlook notes:

Downstate capacity requirements continue to shape where firm resources are needed. Because the highest and most constrained load centers remain in downstate New York, locational capacity requirements continue to drive firm and dispatchable resources near those areas. Even in futures with substantial upstate renewable development, additional firm capacity is often needed closer to load centers to satisfy capacity requirements that cannot be met through statewide totals alone.

Resource availability assumptions create a persistent tension between where clean energy is most developable and where it is most needed. Land-based wind and utility-scale solar are more available in upstate zones, while demand remains concentrated downstate. This creates a recurring planning challenge. The system may have strong opportunities to add clean energy where development potential is greatest, but it still requires transmission capability and additional downstate resources to ensure that energy and capacity can serve load.

This supports my concerns that Climate Act implementation treats land use, transmission corridors, and community opposition as solvable details, whereas the system modeling shows they materially shape feasible resource portfolios.

Recommendations

NYISO finds that growing demand and planned fossil retirements mean the system needs “substantial new investment in reliable generation and transmission infrastructure” across all futures. They recommend prioritizing timely development of new resources, especially in policy driven scenarios that require much more installed capacity than exists today.

A central recommendation is to “establish a viable path for the development of resources capable of providing firm capacity and operational flexibility as the generation mix evolves,” explicitly recognizing the need for dispatchable, firm resources even in highly decarbonized futures. NYISO also calls for coordinating the timing of resource additions, repowering, and retirements to reduce transition risk and avoid tightening system conditions during the Climate Act transition.

On the transmission side, the Outlook urges targeted enhancements to increase transfer capability across the Central East interface (e.g., dynamic voltage support) and bulk transmission upgrades to support zero emissions generation development in Northern New York. These are framed as necessary to reduce congestion, improve deliverability, and allow new renewables and firm resources to actually serve downstate load.

Conclusion

The NYISO recommendations address my concerns that: (1) reliability requires firm capacity (DEFRs or equivalent), not just wind/solar/storage; (2) the timing of retirements versus new builds is critical; and (3) transmission constraints are central to Climate Act implementation feasibility, and (4) it is long past time that a feasibility analysis be completed to define New York’s energy future. NYISO’s call for “a viable path” for firm resources and its acknowledgment that policy driven zero emissions futures demand far more capacity than today are similar to my warnings about the DEFR gap and the risk of retiring peakers without firm backup.  Until Climate Act implementation policy aligns with the NYISO Outlook the risks of reliability problems is a serious concern.  The difference in costs for all the new resources necessary for zero emissions versus costs for the relaxed emission scenarios relative to the differences in emissions for the two approaches should be an energy policy discussion point.

Alle-Catt: A Climate Act Project Doing More Harm Than Good

During my career as an air pollution meteorologist, I have done many air quality assessments for new or existing permits.  That process is rigidly quantitative.  The agencies and the applicants must follow specific assessment protocols to determine whether the facility meets specific numerical limits.  If the facility cannot meet those limits the permit to construct or continue to operate cannot be granted.  Period.  This post documents the situation for the Alle-Catt Wind Energy Center where the state permitting process has managed to let the applicant construct wind turbines that cannot lawfully operate because it cannot meet its own noise protection conditions. 

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, affordability risks, and unacceptable environmental impacts.  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

Invenergy’s Alle-Catt Wind Energy Center is a 340-megawatt wind power generation facility in Allegany, Cattaraugus, and Wyoming Counties, New York.  The permitting case is 17-F-0282 – Alle-Catt Wind Energy LLC.  Cattaraugus County Legislator Brenda S. Hanson filed a letter on June 30, 2026 requesting information regarding the current permitting situation:

I write as a duly elected Cattaraugus County Legislator representing constituents who reside in close proximity to the Alle-Catt Wind Farm project in the Towns of Farmersville and Freedom. My constituents and I welcome the Siting Board’s June 23, 2026 denial of Alle-Catt Wind Energy LLC’s petition to amend its Certificate of Environmental Compatibility and Public Need to remove Certificate Condition 68(d)(vi) — the requirement to demonstrate, through pre-construction noise modeling, conformance with the L(night) Design Goal of 40 dBA annual equivalent continuous average nighttime sound level outside any existing non-participating residence.

That denial raises three urgent and distinct questions that I respectfully ask the Board and DPS staff to answer in writing: (1) What is Alle-Catt now obligated to do? (2) Does that obligation extend to turbines already erected in Rushford and Farmersville? (3) What happens if Alle-Catt fails to comply, and who enforces it?

This is Exhibit A in my argument that the environmental permitting process for renewable energy in New York is broken. 

Noise Limit Issues

Alle‑Catt’s Article 10 certificate includes Condition 68(d)(vi), which requires the developer to file a Pre‑Construction Noise Impact Assessment (PNIA) at least 60 days before “Commencement of Full Construction.” That PNIA must demonstrate, through sound modeling, that the project as finally designed will meet a 40 dBA annual equivalent nighttime sound level (Lnight‑outside) at all existing non‑participating residences. In other words, the turbines are not supposed to be built, let alone operated, unless the design can be shown up front to protect neighbors from chronic nighttime noise above 40 dBA.

Cattaraugus County Legislator Brenda Hanson notes in her June 24, 2026 letter that Alle‑Catt’s own December 3, 2025 PNIA predicts that noise at “most receptors” will exceed the 40 dBA Lnight goal. The Coalition of Concerned Citizens’ attorney, Gary Abraham, points out that Alle‑Catt’s later, March 24, 2026 PNIA—filed in redacted form—also shows annual nighttime noise above 40 dBA at many non‑participating homes, even after the applicant’s modeling tricks.

Independent acoustician Robert Rand goes further. Using the methodology the Siting Board actually approved in prior wind cases (Bluestone and Deer River), he reconstructs Alle‑Catt’s long‑term nighttime source power and propagation and concludes that restoring the project’s 2 dB “discount” from an improper ground absorption factor shows the 40 dBA Lnight goal cannot be met at 19 non‑participating residences and 36 non‑participating properties. In addition, there are hundreds of acoustic paths from turbines to residents with concave topography, where the receptor is in a line of sight to the turbine and little or no ground absorption occurs to dampen the noise. Alle-Catt acknowledged this problem in earlier PNIAs but avoided analyzing it in its latest one. In short, under valid assumptions, Alle‑Catt is not designed to  meet the noise condition the developer accepted when it took the certificate.

Inexplicable Siting Board Decision

Despite that, Alle‑Catt has already moved ahead with heavy construction and has erected most of the wind turbines. Hanson’s letter recounts that the Commission’s April 29, 2025 order approved certain compliance filings under Condition 68—specifically 68(a), 68(c)(i), 68(d)(v), (vii), and (viii)—covering excavation, foundations, and erection of the turbines. That is how we arrive at today’s reality: turbines standing in the Towns of Centerville, Rushford and Farmersville, concrete poured and steel in the air.

But the same April 29, 2025 order states, in plain language, that “Alle‑Catt Wind Energy LLC cannot commission or operate any wind turbines” until additional compliance filings under Certificate Conditions 68(b), 68(c)(ii), 68(d)(i), (ii), (iii), and (vi) are approved. Condition 68(d)(vi)—the PNIA demonstrating conformance with the 40 dBA Lnight standard—is explicitly on that list. Hanson rightly asks the Board to confirm that no turbine anywhere in the project area may be commissioned or operated until a compliant PNIA is filed and approved, without exception for turbines already physically erected.  In addition, erection of those turbines violates the Certificate’s requirement to obtain approval of the PNIA at least 60 days prior to commencing full construction.

This is an important point for renewable energy permitting policy: the prohibition is self‑executing. DPS does not need to “decide” to block operation; it has already ordered that Alle‑Catt cannot operate unless and until it proves compliance with the 40 dBA condition. If DPS looks the other way and lets the turbines run without an approved, compliant PNIA, it will be ignoring its own order and its enforcement duty under PSL §168(5).  There is another problem: the Public Service Commission approved commencement of full construction on April 6, 2026, prior to approval of any PNIA for the night noise goal. See DMM No. 883. The June 23, 2026 Order of the Siting Board establishes that no such approval has been granted to date.

On May 7, 2026 Coalition of Concerned Citizens’ attorney, Gary Abraham filed a letter documenting more details about the Siting Board response to the noise condition problem.  Coupled with the Rand filing, they explicitly describe the applicant’s approach and offer evidence that the siting process is broken.  I am not going to provide those details here,

Environmental Impacts

I have long held the position that the Hochul Administration has not properly accounted for cumulative environmental impacts.  In my comments presented on the draft Energy Plan I noted that the last update of the cumulative environmental impact assessment of the transition to net zero was completed in 2020.  Onshore wind projected capacity is 145% higher than previously analyzed, offshore wind is 62% higher, and solar is 241% higher than the maximum scenario expectation in the latest cumulative assessment.

Abraham’s May 7 comments explain that Alle‑Catt’s environmental impacts are not hypothetical.  He reviews the Hearing Examiners’ Recommended Decision and the Siting Board’s certificate order, which estimate 480–515 bird fatalities per year over the life of the project, including six state‑listed threatened or endangered bird species. The record anticipates that at least 41 bald eagle fledglings will be killed or nests will fail over 30 years, associated with one active nest inside the project area and six more close by; most turbines are sited in USFWS “High Mortality Risk to Eagles” zones.

For bats, the project is expected to kill between 26,000 and 39,500 individuals over 30 years, including two species listed as threatened or endangered. Alle‑Catt’s own Exhibit 22 acknowledges that local bat populations will not survive the mortality rate caused by the turbines. On the habitat side, the project removes roughly 1,550 acres of interior forest and fragments about 1,686 acres of unbroken forest out of about 5,900 acres of interior forest in the facility area, degrading movement, breeding, roosting, and nesting behavior for birds and bats.

Since certification, Alle‑Catt has reduced the number of turbines from 116 to 83 and shifted some locations to address landowner concerns, but it retained the original 340 MW capacity by moving to larger Vestas V150‑4.5 machines. Abraham notes that the wind‑swept area of the V150‑4.5 blades (about 17,671 m²) is roughly 20% larger than the GE 3.6‑137 machines modeled in the 2019 PNIA (~14,741 m²). Larger swept area means more blade surface moving through air and thus increased collision risk for birds, bats, and insects, plus an expanded noise footprint, offsetting the modest impact reductions that might have come from fewer towers.  Low frequency thumping sounds as blades cross the tower every second also increases.

The State Department of Health testified during the Article 10 process that the noise levels approved for Alle‑Catt would pose a public‑health risk to host communities, and that shadow flicker above 30 hours per year and 30 minutes per day would likewise be a health concern. The Siting Board rejected DOH’s recommended per‑day limit and noise limit, instead adopting the noise and flicker limits requested by the applicant. Alle-Catt was silent about the night noise requirement, included in all other Article 10 Certificates, but the Siting Board added that to the Certificate after Abraham pointed it out and Alle-Catt accepted it. That was in June 2020. Those decisions are now colliding with Alle‑Catt’s inability to demonstrate compliance even with applicant‑friendly assumptions.

The impacts of these 83 wind turbines are significant.  The State Energy Plan Net Zero scenario projects that 15,700 MW of onshore wind capacity will be needed to meet Climate Act goals.  That equates to 3,800 similar turbines and, if environmental impacts are proportional, statewide environmental impacts 46 times higher than these 83 wind turbines. 

Now What?

Hanson’s letter lays out a layered enforcement framework that now hangs over Alle‑Catt.

  1. PSC has already ordered that Alle‑Catt cannot commission or operate any turbines until a compliant PNIA under 68(d)(vi) is approved.
  2. Certificate Condition 10 gives DPS staff authority to issue stop‑work or stop‑operation orders wherever construction or maintenance violates the certificate or a DPS order.
  3. The certificate spells out a non‑compliance remediation timeline: within 60 days of a non‑compliance finding, Alle‑Catt must file operational and physical minimization options; within 90 days, it must implement operational mitigation; within 150 days, physical mitigation—and if those are not timely implemented, the non‑compliant turbines “must not be operated” until compliance is shown.
  4. Certificate Condition 17 allows the Board to seek penalties not only against the certificate holder but its contractors, and 16 NYCRR 1000.16(e) preserves the Board’s jurisdiction to suspend or revoke the certificate at any point before the final compliance filing is approved. Finally, Public Service Law §168(5) requires DPS to “monitor, enforce and administer” compliance with certificate terms. Hanson asks DPS to confirm in writing that it will use these tools if Alle‑Catt attempts to operate without meeting the 40 dBA Lnight condition.

From a Climate Act permitting perspective, that enforcement puzzle is telling. Either DPS enforces its own orders and certificates, which may leave Alle‑Catt as a stranded, non‑operating monument to bad siting and unrealistic transmission assumptions, or it loosens protections and quietly tolerates non‑compliance to keep the project on the books as “renewable capacity” helping to meet goals. Neither path is a triumph for the environment and non-compliance is not protective of health.

It gets worse.  Abraham’s letter also shows that claimed climate benefits—downstate emissions reductions—depend on transmission upgrades that do not exist and are not planned, in a grid region that is already largely carbon‑free. The project’s output will mostly displace other low‑carbon resources, not fossil generation, and it cannot shut down upstate fossil plants because they are needed to back up intermittent wind. New York is asking rural communities to absorb irreversible environmental and health impacts for a project whose net emissions benefits are “meager” at best.

UPDATE I have been told that today, On July 23, 2026, Cattaraugus County and Abraham’s Coalition of five environmental groups filed petitions requesting that the Siting Board declare what Alle-Catt’s obligations are in light of the Board’s refusal to remove the night noise goal, and Alle-Catt’s inability to demonstrate it can comply. The petitions note that permission to proceed with operations must still be obtained. We will have to wait and see how the Board resolves this mess.

Conclusion

Alle‑Catt shows what Climate Act renewable energy implementation looks like when you strip away the aspirational language and press releases. A rural region loses interior forest, critical bird and bat habitat, and landscape integrity to hundreds of megawatts of industrial turbines. Neighbors face excessive nighttime noise and shadow flicker that the State Department of Health has already flagged as public‑health risks, while the developer cannot even demonstrate compliance with a noise limit under valid modeling assumptions.

If the Climate Act is going to produce more benefit than harm, permitting for projects like Alle‑Catt need to be confronted honestly. That means re‑examining not only noise and wildlife conditions, but also the assumption that any renewable project located anywhere in the state automatically advances climate goals. On the record before us in Case 17‑F‑0282, Alle‑Catt does not. It is a stranded Climate Act project whose primary legacy, so far, is environmental degradation and regulatory contortions, not meaningful emissions reductions.