Small-Scale Solar Is Reshaping New York's Midday Power Demand
EIA data show rooftop PV has flipped the NYISO morning demand curve and tripled the evening ramp since 2018.
New York's small-scale solar buildout has grown large enough to visibly reshape the state's hourly electricity demand, with EIA data published on Thursday (2026-06-26) showing that midday consumption has dropped sharply as behind-the-meter generation surged.2
The EIA analysis covers changes in New York ISO metered demand between spring 2018 and spring 2026. Roughly half of the 5.6 GW of photovoltaic capacity added in New York over that period consists of small-scale, rooftop or behind-the-meter installations — the kind that reduce demand visible to NYISO without appearing on its generation ledger.2
The numbers illustrate how much has changed. In March and April 2018, hourly electricity demand in New York increased by an average of 850 MW during the three-hour morning window between 8:00 a.m. and 11:00 a.m., as commercial buildings and industrial loads came online. By the same months in 2026, demand during that window was falling by an average of 923 MW — a swing of 1,773 MW in eight years, driven by behind-the-meter solar generation peaking during those hours.2
The evening reversal is sharper still. In March and April 2018, NYISO metered demand climbed by an average of 681 MW between 4:00 p.m. and 7:00 p.m. as solar faded and evening loads picked up. By 2026, that same three-hour ramp has grown to 2,221 MW on average — more than three times the 2018 figure — because grid operators must cover both the loss of behind-the-meter output and the natural increase in evening load simultaneously.2
This is the duck-curve dynamic now established at measurable scale inside a major US grid. Midday demand on NYISO's metered feed is suppressed, making the grid look light during peak solar hours. Then demand surges in a compressed window as the sun sets. The grid's flexibility requirement — the capacity to ramp quickly, not just to provide peak energy — becomes the binding constraint rather than total installed capacity.2
The implications for gas dispatch are direct. Gas-fired peakers and combined-cycle units in New York that once ran during the midday shoulder period now face lower dispatch frequency in those hours. Revenue shifts toward the late afternoon ramp, shortening the daily utilization window and putting a premium on fast-start capability over sustained baseload output.2
The effect is most pronounced in early spring, the EIA noted, because solar irradiance is rising while heating demand has dropped but cooling demand has not yet started. The solar output peak is largest in that seasonal window — demand dips deepest at noon, ramps hardest at dusk. Summer months introduce air conditioning load that partially masks the midday suppression, but the evening ramp effect persists year-round.2
NYISO has been managing distributed generation impacts for several years, but the EIA data clarify that small-scale PV — not utility-scale arrays with grid interconnections — now accounts for a material share of the structural demand shift. Behind-the-meter capacity is harder to dispatch, curtail, or forecast because it sits outside NYISO's direct control. The grid operator sees only the residual demand after that generation has run, which increasingly understates the total system load picture.2
The installed base keeps growing. Analysts expect solar to remain the dominant growth engine for new US power capacity through continued cost declines and stronger supply chains.1 With roughly half of the 5.6 GW added in New York since 2018 in small-scale form, the pipeline of permitted rooftop and community solar installations suggests the evening ramp will widen further.2 Grid planners and capacity market participants watching NYISO's next capacity auctions will need to model not just total peak demand but the speed at which demand can rise in the post-solar hours — a metric the current auction design does not explicitly price.