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

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

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

What the paper argues

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Bottom Line

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

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

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

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

What the Build-Ready Program Was Supposed to Do

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

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

Section 3.1 Is Where the Report Gets Honest

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

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

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

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

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

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

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

The Money

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

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

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

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

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

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

The Bottom Line

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

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

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

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

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

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

What the poll found

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

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

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

RGGI is already failing the poll’s own test.

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

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

Where the money actually goes

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

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

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

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

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

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

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

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

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

Discussion

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

Conclusion

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

New York Energy Policy BESS Disconnect

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

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

The Problem

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

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

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

Battery Requirements

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

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

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

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

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

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

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

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

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

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

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

Alternatives

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

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

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

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

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

Practical Scenario

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

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

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

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

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

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

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

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

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

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

Conclusion:

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

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

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

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

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

Background

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

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

Timeline

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

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

Factors not Considered

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

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

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

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

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

Bottom Line

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

How Neighboring Electric Systems Handled the July 2026 Heat Wave

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

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

Personal Concerns
- Ideological purity over pragmatic tradeoffs
- Insufficient documentation (Perplexity AI Summary)
- Flawed implementation process (Perplexity AI Summary)
- More harm than good
Primary personal concern has always been affordability

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

Academics premise of CLCPA transition (Perplexity AI Summary)
Energy Transition build plan (Perplexity AI Summary)
Feasibility

Source: Climate Act Scoping Plan

Scoping Plan
- Goal
- Completion
- Affordability slogan (Perplexity AI Summary) “The costs of inaction are more than the costs of action”

State Energy Plan
- Requirement
- Goal
- Same failure to include a base case without all the CLCPA costs Draft NYS Energy Plan Pathways Scenario Scam
- Affordability message (Perplexity AI Summary):
  - Future energy costs necessarily will increase substantially and the costs to comply with the CLCPA are relatively small

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

Why Affordability Matters Now
- Nearly 1.3 million households were 60+ days behind on utility bills in 2025
- Total arrears exceeded $1.8 billion at the end of 2025
- The biggest costs are still ahead of us

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

Costs of inaction are more than the cost of action (Perplexity AI Summary)
- Benefits are societal but costs are real
- Avoided GHG benefits calculated incorrectly
- Costs are incomplete – do not include all funds needed to achieve CLCPA mandates
Affordability References
- Climate Act Costs and Benefits
- Scoping plan analyses of costs
- Scoping plan analysis of the benefits

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
- Equipment Costs Implications Article on the NYSERDA Energy Plan Fact Sheet

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

Source: NYS Energy Planning Board Meeting Presentation Slide 43

Energy Affordability with equipment costs
- The December 2025 Energy Affordability Data Annex spreadsheet (Annex Spreadsheet) and the Energy Affordability Impacts Analysis (Perplexity AI Summary) document provide the supporting documentation for the Fact Sheet.

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

Kris Martin NY Solar Divide Substack
- September 20, 2025: “Where the money comes from”
October 18, 2025: “What it costs – How solar and wind buildout affects NY electric bills”

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.

NYISO Key Findings Affecting Affordability
- NYISO 2025-2044 System & Resource Outlook
- Policy stringency
- Hydrogen dependency is a cost & reliability risk to avoid
- New resources and retirement planning
- Transmission bottlenecks
- Siting large loads matters

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

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.