Rochester Beacon Guest Opinion: Why New Yorkers pay more for electricity than the average American
May 28th, 2026
By JUSTIN WILCOX – May 27, 2026
Read the full article here.
New York families paid two thirds more for electricity than the national average in February, according to the Energy Information Administration—and it’s not because the wires cost more here. It’s because Albany rewrote the rules.
Over the past decade, New York didn’t simply reform its energy markets—it dismantled them. In their place, lawmakers installed a system in which investment decisions are no longer driven by price signals but by policy mandates, subsidies, and permitting discretion. Projects struggle to pencil out, needed generation gets blocked or delayed, and private investors refuse to build without state-backed contracts that include revenue guarantees. Whatever this system is, New York no longer has functioning competitive markets—and ratepayers are paying the difference in cost.
This dismantling is especially striking given what New York’s competitive markets had achieved. In “The New York Independent System Operator: A Ten-Year Review,” a study commissioned by NYISO, the economic consulting firm Analysis Group documented wholesale markets that worked. Quoting staff of the New York Public Service Commission, the review noted that New York’s wholesale markets had become “among the most advanced in the nation,” with competition delivering “significant efficiencies.” Thousands of megawatts of new generating capacity were added over NYISO’s first decade, ending in 2009—much of it built close to the population centers where it was needed, and with “most of the financial risk borne by investors rather than by electricity customers.” Power plants grew more efficient. Reliability margins exceeded required levels. That is the system Albany chose to dismantle.
The economics speak for themselves. In its “2025 Renewables Strategic Plan,” the New York Power Authority— the public entity Albany has tasked with expanding renewable development—found that “based on modeling of merchant revenue streams (energy, capacity, and ancillary services), projects can expect to make less than $50/megawatt hour (MWh) on an annual basis for the foreseeable future.”Atthe same time, NYPA reported that”the (levelized cost of electricity) for new solar has increased to at least $100/MWh.” NYPA’s conclusion was direct:”new renewable energy projects cannot cover their costs just selling their outputs into the NYISO market alone.”
That gap is structural, not temporary. In a functioning market, it would be a signal not to build. In New York, the gap is filled by subsidies and long-term contracts funded by ratepayers.
In a functioning market, scarcity sends a clear signal: build more generation, capture the higher prices, and the system rebalances. New York’s market is no longer functioning that way. In 2019, the state enacted the Climate Leadership and Community Protection Act—the nation’s most ambitious greenhouse gas reduction law—which requires, among other things, that all electricity generation be zero-emission by 2040. The result is that the price signal to build goes out but developers can’t make the economics work without ratepayer-backed contracts. The market is sending a signal. New York’s energy sector can’t afford to respond.
Even that subsidy-driven system is proving unstable. In 2023, renewable energy developers returned to the PSC seeking to renegotiate contracts after dramatic cost increases—some requesting price adjustments of up to 50 percent. The commission unanimously rejected those requests, warning they would impose billions of dollars in additional costs on consumers. Projects stalled, contracts were terminated, and the state was forced back to the drawing board.
State policy is also reshaping what gets built long before any contract or permit is finalized. With binding emissions mandates and uncertainty around permitting outcomes, developers assume that long-term investments face both regulatory and financial risks. Projects move forward only when backed by state contracts or subsidies that insulate them from those risks.
NYISO, the grid operator, has been warning about the consequences—and its warnings carry particular weight. It operates the wholesale electricity markets that still function in New York, balancing supply and demand in real time within whatever policy framework Albany sets. It does not make energy policy. It manages the grid those policies produce. And what it is now managing, by its own account, is a grid under increasing strain—not because competitive markets have failed, but because the policy environment has constrained what markets can deliver.
NYISO’s “Power Trends 2025” report found that “the pace of generator deactivations is exceeding the development of new generating resources. Since the passage of the state’s 2019 CLCPA, 4,315 MW have left the system while only 2,274 MW have been added—a net loss of more than 2,000 MW”—enough capacity, NYISO noted, to power roughly 2 million homes. Decreasing supply against sustained demand does not require a complex explanation. It produces scarcity, and scarcity drives up prices. Eventually, it can lead to outages. While this may have been an unintended consequence, it was not unforeseeable. It is what happens when you retire generation faster than you replace it—and call it a plan.
The same report warned that as reliability margins narrow, “consumers face greater risks of outages if the resources needed for reliability are forced out of service by policy mandates or failures associated with aging equipment.” Months later, NYISO’s “Summer 2026 Reliability Assessment” confirmed the deterioration was already visible. NYISO’s press release for the report cited “declining reliability margins, performance issues with aging generators, and an absence of new dispatchable resources.”
That assessment was foreshadowed by specific permitting decisions: in 2021, two merchant developers attempted to repower existing natural gas facilities for the wholesale market, only to be denied the air permits required to proceed—a direct result of regulators’ interpretation of the CLCPA’s zero-emissions mandate.
The pattern is now clear. New York’s climate goals as embodied in the CLCPA are legitimate—but the way the state has pursued them has hobbled the energy market’s ability to respond to demand. Investment is no longer guided by price signals; it is filtered through policy approval at every stage. NYISO’s own “Power Trends 2025” report acknowledges “noticeable increases in capacity charges” and “market volatility, characterized by fluctuating or increased prices” as direct consequences of the transition.
Unfortunately, even the CLCPA amendments recently adopted within this year’s state budget don’t fix any of this. They adjust deadlines and soften some near-term targets, but they leave intact the underlying structure that has displaced competitive markets with policy mandates, ratepayer-backed contracts, and permitting discretion. Pushing compliance dates further out may relieve short-term political pressure, but it does nothing to restore the price signals that once drove private investment in the generation New York needs. It is, in effect, kicking the can down the road.
This is why struggling New Yorkers are already paying 30 cents per kWh while the national average is 18. And that’s why that gap will keep growing, pushing ratepayers, workers, and employers toward states where energy is affordable and the rules are stable. New York can decarbonize this way—a smaller economy uses less power. But that is not a climate strategy. It is a managed decline with climate consequences as a side effect—and the price is being paid by the New Yorkers least able to absorb it.
Justin Wilcox is executive director of Upstate United, an economic advocacy coalition.