I have not updated my Reasons to Pause the Climate Act page in months. In the meantime, the evidence that the Climate Leadership & Community Protection Act (Climate Act) approach is unworkable keeps piling up and has reached the point that I think it is time to decide what New York’s energy future should look like. This post covers three overarching reasons New York should pause the net-zero transition until it decides what it wants the future energy system to look like: mineral supply constraints, the risk of depending on our neighbors when we need power most, and the lack of honest numbers about the cost of electrifying everything.
I have followed the Climate Act since it was first proposed and am convinced its implementation plan will adversely affect affordability and reliability. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with; these comments are mine alone. I acknowledge the use of Perplexity AI to research the material summarized in this article and prepare an initial draft.
The Climate Act implementation plan relies on wind, solar, and energy storage, plus a yet-to-be-developed category of dispatchable emissions-free resources (DEFR) to keep the lights on during extended periods of low wind and solar output. Nearly seven years after passage, the State still has not answered the fundamental question: what will the electric system look like when the transition is complete, and what will it cost?
Stu Turley at Energy News Beat recently published The World Is Running Out of Easy Ore. Stop Building Two Grids. His argument is that geology and manufacturing capacity, not political schedules, will determine how fast the energy system can change.
Turley, drawing on Peter Clack, explains that copper ore grades have fallen sharply since the early 1990s, so miners move far more rock, using more energy and water, for the same metal. At the same time, a new copper or lithium mine takes 12 to 17 years to develop, while net-zero mandates run on five-to-ten-year clocks. He cites the International Energy Agency’s 2025 outlook projecting a roughly 30 percent copper shortfall by 2035, lithium deficits in the 2030s, and rare-earth magnet processing concentrated in a single dominant supplier.
The mineral intensity of different resources matters. According to the IEA and World Nuclear Association figures he cites, coal and gas use roughly 7 to 8 tonnes of critical minerals per lifetime terawatt-hour, nuclear about 12, and solar and wind 124 to 200. An offshore wind plant can require about 13 times the minerals of a comparable gas plant. When the resource that uses the scarcest minerals is also the one that needs the most backup, transmission, and storage, costs are going to go up.
He also documents a grid hardware bottleneck: the United States makes only about a fifth of the large power transformers it needs, and lead times now run two to five years. Turley cites a 2026 National Center for Energy Analytics study of PJM that estimated a wind-solar-battery build would cost ratepayers more than $4 trillion over 20 years, about six times a gas-and-nuclear path, because it needs roughly ten times the nameplate capacity to ride through multi-day renewable droughts.
His central point is that we are paying for “two grids”: the physical grid that obeys physics and the policy grid that pays for mandates. The intermittent approach requires duplicate capacity, extra transmission copper, and storage that does not yet exist at scale. That describes the Climate Act plan, which needs wind, solar, storage, and DEFR.
His recommendations deserve emphasis because they describe a practical alternative. He proposes a priority test: firm megawatt-hours per ton of copper, nickel, and rare earths, and per dollar of full system cost, with supply chains under allied control. He recommends:
- Restart sound nuclear units.
- License new large reactors and small modular designs consistent with the Department of Energy’s goal of moving from about 100 GW toward 400 GW by 2050.
- Build gas plants for the years before reactors are available, because they are the lowest-mineral, fastest dispatchable option.
- Treat transformers, electrical steel, and high-voltage equipment as defense production and standardize designs that pays off in cost, licensing, operations and safety.
- Let data centers connect when they bring firm power and hardware, not just a queue position.
- Mine and refine copper, uranium, and rare earths on U.S. and allied ground, recognizing that recycling helps but cannot close a 30 percent copper gap.
- Stop building the “second grid” of intermittent resources that require duplicate capacity.
New York’s plan does almost the opposite. It prioritizes the most mineral-intensive resources, phases out the fossil-fired generation that keeps the system reliable today, and treats DEFR as a problem to solve later rather than acknowledging that DEFR is necessary for the wind and solar system proposed.
New York Cannot Count on Its Neighbors
Meredith Angwin’s A Tale of Two Transmission Lines compares the two new high-voltage direct current lines that bring Québec hydropower to the Northeast. The New England Clean Energy Connect (NECEC) line to Maine is designed for 1,200 MW and the Champlain Hudson Power Express (CHPE) to Astoria in Queens is designed for 1,250 MW.
The NECEC is a comparatively simple overhead line. However, during a cold snap shortly after it went into service in January, Hydro-Québec stopped sending power for almost two days because it needed the electricity for its own customers. Angwin describes that as a policy decision: Québec is winter-peaking, and when it gets cold, Québec takes care of Québec first.
The CHPE is a 339-mile underground and underwater line. When Angwin wrote in late July, it had been down most of the month because of two physical failures. The Daily Gazette reported that a July 1 problem at a Canadian substation was fixed the next day, but a damaged cable splice in New York knocked the line out on July 4, during a heat wave. She notes that burying the line for aesthetic and ecological reasons made it more fragile because faults are harder to find and fix.
The line returned to service on July 25, but its performance since then reinforces her point. Modo Energy found that CHPE’s first-summer capacity factor was 13 percent, with 25 percent in August and 30 percent in September. That compares with the roughly 95 percent implied by the contract for 10.4 TWh a year. Since early August, the line has delivered power in an afternoon-to-evening block and sat at zero overnight. Modo also found that New York was a net exporter to Québec across the three Hydro-Québec ties this summer. Energy News Beat reported that at the 3 PM peak on August 26, the Hydro-Québec ties, including CHPE, delivered zero megawatts. Meanwhile, CBC reported that Hydro-Québec expects 2026 energy reserves of 86 TWh, down from 97 TWh in 2024 and below the 100 TWh it considers comfortable. Hydro-Québec says Québec’s needs remain the priority.
Her most important point is that this is ultimately a resource adequacy issue, not a transmission issue. Today, Québec has surplus power in the summer and the U.S. can help Québec in the winter. Electrifying vehicles in Québec and heating in the United States could eliminate the “extra” capacity both sides now share. In her words, “you need to produce the electricity before you can move it.”
The NYISO Summer 2026 Operating Study shows how much New York already depends on imports. NYISO concluded that the system can be operated reliably this summer, but look at the numbers. The Installed Capacity requirement was 39,315 MW, based on a 24.5 percent reserve margin. In-state generation capacity was 38,027 MW, so New York could not meet its own reserve requirement without the 3,168.5 MW of net external capacity purchases that were secured. The study assumed 6,164 MW of capacity would be unavailable because of forced outages and derates. NYISO notes that 1,225 MW of generation retired, including Gowanus, Narrows, and Danskammer, are scheduled to be retired, while only 225 MW was added. Gowanus and Narrows are treated as necessary resources under the short-term reliability process through May 1, 2029. The study models CHPE at a maximum delivery of 1,250 MW into New York and 0 MW in the other direction. For comparison, the largest single generator contingency NYISO plans for is Nine Mile Point 2 at 1,310 MW. Losing CHPE is like losing one of the largest power plants in the state.
My concern is not that PJM or ISO-NE will necessarily be unable to export power. It is that their ability to provide dependable assistance is most questionable precisely when New York needs it most:
- A Northeast-wide heat wave.
- A prolonged winter cold spell.
- Widespread generator derates or fuel constraints.
- Transmission outages that reduce interface capability.
In each case our neighbors will face the same weather, the same fuel constraints, and their own customers first. Québec already showed us what happens during a cold snap. Retiring fossil generation while increasing reliance on imports and weather-dependent resources makes New York more exposed to exactly these correlated risks.
FERC’s current large-load proceedings make this a timely issue. As described by Sheppard, on June 18, 2026, FERC issued show-cause orders to six RTOs and ISOs, including NYISO, PJM, and ISO-NE, preliminarily finding their tariff treatment of large loads unjust and unreasonable. The orders call for improved load forecasting, large-load impact studies, and cost recovery agreements to protect other ratepayers, and each RTO had to report on the status of resource adequacy within 30 days. FERC recognizes that new large demand requires clearer planning, interconnection, and cost-allocation treatment in each region. If every neighboring RTO is scrambling to serve its own data centers, it is even less likely they will have spare capacity for New York during a regional emergency.
Matt Jacobson’s Before You Electrify Your State, Do the Math is about Maine, but every point applies to New York. After seven Maine winters with heat pumps, he likes them, but when it gets really cold they are expensive to run, so he switches to his oil furnace or wood stove. As he puts it, “My house has choices.”
Jacobson walks through the arithmetic. Central Maine Power customers pay about 25 cents per kWh. A fully electrified home using 15,000 to 20,000 kWh a year would pay roughly $3,700 to $4,900 a year for electricity. If rates stay the same and usage doubles, the bill roughly doubles, but rates will not stay the same because the system has to be bigger to generate and deliver more power. Remote wind and solar need a “very expensive extension cord,” and neighborhoods need bigger substations and lines.
He also notes that Maine’s Net Energy Billing solar program cost about $313 million in 2025, and that subsidies create a “reverse Robin Hood” effect where those who can afford solar lower their bills while renters and struggling families help pay for it. “A subsidy doesn’t reduce the cost. It changes who pays it.”
His conclusion is that before Maine makes the electrification decision for someone else, “it should have to show us its math.” New York should do the same. After nearly seven years, there still is no clear, transparent, and well-documented description of the costs, emission reductions, and realistic schedules for the Climate Act strategies.
These topics reinforce each other. Mineral constraints mean the resources the Climate Act depends on will be more expensive and slower to deploy than planned. Import dependence means New York cannot assume its neighbors will fill the gaps when wind and solar fall short. Electrification will increase demand in summer and winter, when the system is already stressed, and the State has never shown ratepayers what it will all cost.
New York already has a mechanism to address this. Public Service Law § 66-p(4) allows the Public Service Commission to temporarily suspend or modify renewable energy program obligations if the program impedes safe and adequate electric service or causes a significant increase in arrears or disconnections. At the end of April 2026, the Commission ended a comment period regarding these safety valve provisions. The Commission has not responded to the comments received or defined how those conditions would be tested, so there is no meaningful safety valve.
The Climate Act approach depends on the most mineral-intensive resources that will get more expensive as. minerals get harder to find, imports that are least dependable when we need them most, and electrification without disclosed costs. In addition, there is no deployment plan for DEFR needed to implement a renewable-dependent system. New York needs to pause implementation and decide what it wants its future energy system to look like. That decision should be based on a priority test like the one Turley proposes: firm, reliable power per dollar of total system cost. It should include a realistic assessment of how much New York can count on its neighbors. And, as Jacobson says, the State should have to show us its math before making the decision for everyone else.
