Demand

NYISO demand uses a bottom-up approach, modeling each load component separately. Total zonal load is built from five additive segments, each with its own growth trajectory and intra-day profile:

• Base load: underlying grid demand excluding electrification and distributed generation effects
• BTM solar: behind-the-meter solar PV reduces net load; modeled as a negative load segment with hourly shapes from weather-year irradiance data
• EV charging: electric vehicle load addition, profiled to reflect charging patterns (overnight residential, daytime workplace)
• Building electrification: heat pump and other electrification load, with strong winter seasonality
• Large loads: data centers and industrial facilities added as node-specific step increments

Peak and annual energy values for each component come from the NYISO Gold Book. Hourly shapes are derived from historical weather-year data at the 11-zone level, using heating and cooling degree days to capture each segment’s temperature-driven seasonality.

Building electrification, EV charging, and large loads drive the net energy growth over the horizon, while behind-the-meter solar (shown as a reduction) offsets a rising share of daytime energy.

NYISO-specific notes: historical flows from Quebec and Ontario are subtracted from NYISO load because those regions are not modeled explicitly, and BTM solar profiles assume clear-sky degradation curves with panel density by zone as an input assumption.

MISO load is represented across its ten Local Resource Zones (LRZs) across the Midwest and South footprint. MISO is modeled on year-round Eastern Standard Time (no daylight-saving shift). The forward forecast is anchored to the MISO Long-Term Load Forecast (LTLF) “Current Trajectory” annual coincident peaks by LRZ, with hourly shapes from MISO’s Futures workshop load profiles.

Net energy is built up from per-driver trajectories (residential, commercial, conventional manufacturing, data centers, and electric vehicles), with data centers and conventional manufacturing accounting for most of the growth. Because those are flat, high-load-factor loads, the system load factor rises over the horizon: demand grows without getting much peakier, which shifts BESS value toward capacity and scarcity pricing rather than wider daily arbitrage spreads. Growth also concentrates in MISO Central, where the zones covering Wisconsin/Upper Michigan, Missouri, and Indiana/Kentucky see the strongest data-center-driven growth, which can widen locational price basis.

The MISO forecast draws annual coincident peak by LRZ from the LTLF Current Trajectory and hourly shapes from the MISO Futures workshop data.

MISO-specific notes: EIA-930 reports several MISO sub-regions that are split out to the individual LRZs, and forecast peaks follow the LTLF Current Trajectory (alternative LTLF scenarios are not the default).

PJM load is represented at the transmission-zone level across the footprint. The forward forecast is anchored to the PJM Load Forecast Report, which provides hourly load by transmission zone, with zonal net-export shapes added on top of zonal load.

PJM’s model inputs carry total zonal load, with the only driver breakdown being large-load adjustments. The demand outlook is therefore shown as total annual energy demand across the footprint rather than split by load driver.

PJM-specific note: zone codes are mapped to the model’s zone set for EIA-930, the load forecast, and the interconnection queue.