Category: Climate Act Feasibility

On October 9, 2026 Doreen Harris announced that the New York State Energy Planning Board (Board) will convene on December 9, 2026 to kick off the new Energy Infrastructure Development Plan (EIDP) process.  Earlier this week I characterized it here as process commitment, not the planning commitment I think is needed.   I also had a description posted at the Empire Center for Public Policy. Richard Ellenbogen also responded to the EIDP this week in an email.  This post reproduces his email modified only for posting format. 

Ellenbogen is the President [BIO] of Allied Converters and frequently comments on various issues associated with the New York Climate Leadership and Community Protection Act (Climate Act). I have published other articles by Ellenbogen.  He is an engineer who truly cares about the environment but understands the practicality of clean energy solutions based on his experience as an early adopter of renewable technologies at both his home and business two decades ago.

After Seven Years of NY State’s Failing Energy Policies, The Chickens Are Coming Home to Roost

NY State has been chasing impractical energy goals since they passed the CLCPA in 2019.  Several of us warned the state about the shortsightedness of their policies at that time.   This week, NY State announced the Energy Infrastructure Development Plan (EIDP), while stating, ” The EIDP will complement New York’s existing energy planning process, with the goal of better coordinating how and when new clean energy sources come online.  We’re going to have to build out just a tremendous amount of all of these resources, and we want to make sure that we do it in the most cost-effective way, and we think that’s going to require, effectively, integrated resource planning.  The new initiative comes as the state’s independent grid operator, the New York Independent System Operator (NYISO), announced they are expecting a reliability shortfall in the next decade without state intervention.”

The reason that NY State has the reliability shortfall in the first place that the NYISO is documenting are the very policies that the Hochul Administration now seems to be doubling down on with the EIDP.  They have been focused on shutting down firm generation and putting all of their eggs in the renewable basket.  After seven years those eggs are hatching, and the chickens are coming home to roost as will be clearly documented below.  

The EIDP complementing Energy policies that aren’t working won’t make them work any better.  It will only throw good money after bad and raise costs.  That is currently happening with NYPA’s purchasing solar arrays that the private developers can’t afford and ultimately dumping the costs onto the backs of ratepayers and taxpayers while claiming to perform a public service.

A large reason for the debacle is that whenever engineers propose a plan, one of the first steps is to ensure that the resources exist to make the plan work.  However, NY State’s Energy Plan wasn’t designed by engineers.  It was designed by a biologist and some climate activists and  NY State skipped the resource adequacy step with their energy planning.  The state has evidently been hoping for the past seven years that a fairy godmother would step in to fix the mess because nothing in the current planning coming out of Albany is going to address the issues.  In August 2023, I wrote a document for the PSC as part of 15-E-0302 explaining why the CLCPA would not work.  On page 4 of the filing, the following five issues are documented.  Note the issues documented in number 2, below.

In the last week, two documents have been published.  One was sent out by Robert Bryce on his Substack titled “The Great Grid Hardware Shock“, and clearly documents the rapid rise in equipment costs, much of it due to shortages.  For example, there has been an acute transformer shortage for many years.  A second document published on October 4, titled “The World is Running Out of Ore“, shows that the world is running out of copper.  The use of renewable generation compounds the problem.  Why is that?  

The following table shows the land areas and annual energy outputs of 500 Megawatt generators in solar, wind, gas, and nuclear.  

As the power capacities are all the same, the electrical conductors will have to be similarly sized for the peak power output but as can clearly be seen, the solar array is 230 times larger per Terawatt-hour than the equivalent sized gas plant (5070 acres vs. 22 acres) and only produces 30% of the annual energy of the gas plant  (740 GWh vs. 2492 GWh).  The full comparison uses numbers based on EIA documentation for NY State.  The vastly larger area will require far more transmission capacity for 30% of the energy output. 

For wind in NY State, the numbers are worse.  The wind farm is 1800 times larger per terawatt-hour than the gas plant.  The nuclear plant is five times larger per terawatt-hour than the gas plant, but it generates 62% more energy.  These numbers clearly explain why so many renewable projects are failing in NY State.  They are just too expensive so if NY State truly wants to be “Cost effective”, as they claim, they are going to have to rethink their policies. 

The CleanPath Project (Renewable Transmission Cable and Generation) that failed in late 2024 is an example of the issues.  It was too expensive for the amount of energy that it would provide.  The following graph, copied from “The World is running out of Ore” document, shows the relative ore costs per terawatt-hour of generation for various generating technologies.  It shows exactly what was explained previously.  The energy systems with a lower power density occupy much larger areas, generate less energy,  and have far higher costs per unit of energy generated.  

Source: The World is running out of Ore

It isn’t just copper that is in short supply.  Aluminum is also in short supply because several smelters have closed over the past several years due to high energy costs.  

Beyond the material shortages are the labor shortages. It requires far more labor to interconnect a 40,000 acre generating plant  than a 22 acre or a  100 acre generating plant.

In addition to the costs of the interconnections are the costs of the associated equipment needed to make renewables functional on the utility system.  That includes synchronous condensers needed to add grid inertia to a  renewable system.  Also needed will be large amounts of energy storage for times of low wind and sun.  Based upon NYSERDA’s 6 GW Energy Storage report, the required energy storage could cost between $2 Trillion and $3 Trillion to achieve the same functionality as the Combined Cycle Gas plants or the Nuclear Plants.  No one at the state level has ever explained where the trillions of dollars are going to come from.

The state government is talking about reducing energy costs while adopting policies that are going to increase costs and are simultaneously  impossible to implement due to resource inadequacy.

If NY State can’t build what they are planning, they will never solve the generation shortfall we are currently living with.  What the facts are showing is that there is no cost-effective way to build out the renewable resources that they seem determined to inflict upon the State’s ratepayers in opposition to math, physics, and economics.

It will only get worse as the older, existing firm generation plants fail because of age.  We will all be living in the dark and paying more for the privilege.

State Energy Planning Board to Kick Off New Energy Infrastructure Development Plan Process

In closing for my reader’s attention I enclose the text of the Doreen Harris announcement.  Ellenbogen and I agree that there is no suggestion that the State is really willing to address the challenges he has described here because there is no acknowledgement that there are issues.

I’m pleased to share that the New York State Energy Planning Board (Board) will convene on December 9, 2026. The meeting will kick off the new Energy Infrastructure Development Plan (EIDP) process as part of the ongoing New York State Energy Plan work to provide an actionable plan for the infrastructure that New York needs to modernize its power grid and keep pace with the energy demands of economic growth. Importantly, the plan will guide the State’s energy infrastructure investment decisions over the coming decades and supports Governor Hochul’s Climate Week directive as part of her Clean, Highly Affordable, Reliable Grid Expansion (CHARGE) agenda to advance affordable, abundant, reliable, and clean energy within New York State.

The Board and supporting State agency staff will establish a transparent process to release an interim plan in 2027 and to finalize the first comprehensive Energy Infrastructure Development Plan by December 2029. The forthcoming EIDP process will include multiple opportunities for energy industry stakeholders and the public to engage and provide input.

I invite you to attend the meeting to be held at the Albany Capital Center, Meeting Room 2B/2C at 55 Eagle St, Albany, New York beginning at 2:00 p.m. ET. This meeting is open to the public for listening, both virtually and in-person with registration.

I look forward to reconvening the Board to address New York’s energy needs through an expanded planning framework.

Stay tuned.

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

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

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

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

The reliability-first message

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

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

At present, the State’s energy strategy relies heavily on weather-dependent wind and solar generation, battery energy storage systems, new transmission, imports, demand-side resources, and a future resource category called Dispatchable Emission-Free Resources, or “DEFRs.” The problem is that “DEFR” is a planning category, not a resource. New York State has not identified a specific technology that has been built, financed, permitted, interconnected, tested, and demonstrated at the scale New York needs.

The basic principle presented to NYPA was therefore simple:

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

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

New York has two different grid challenges

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

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

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

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

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

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

“The Grid Is Already Broken”

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

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

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

Source: Data provided by Rich Ellenbogen

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

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

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

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

The unresolved DEFR question

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

The presentation cited a potential need for more than 10 GW of yet-to-be-identified DEFR capacity within the next several years. If that scale of dependable capacity is necessary, State policymakers and NYPA should answer basic questions now:

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

The State should not presume that a future technology will be available simply because planners have assigned it a useful name. Before existing dependable resources are retired, replacements should be specific, operational, and stress-tested.

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

Wind, solar, batteries, and difficult weather

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

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

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

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

Table 1: Hourly Data for June 29, 2026

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

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

Nuclear and the transition gap

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

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

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

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

A constructive role for NYPA

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

The presentation identified several areas for NYPA consideration:

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

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

Conclusion

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

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

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

Overview

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

PJM: The Most Acute Stress in the Country

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

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

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

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

ISO New England: Tight, But Wind Actually Helped

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

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

MISO: High Load, Weak Wind, No Emergency

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

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

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

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

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

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

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

Comparing the Regions

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

Conclusion

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

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

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.