The forecast spans three scenarios covering a range of market outlooks: a central case, an accelerated renewables buildout, and load growth that substantially undershoots the current outlook.
Overview matrix
Each scenario adjusts a set of levers relative to the Central Scenario. Bold values differ from the Central Scenario.
| Lever | Central Scenario | High Renewables | Low Demand |
|---|---|---|---|
| NREL ATB capital cost trajectory | Default | Advanced for renewables | Default |
| Gas and coal fuel prices | Reference case | +10% | Reference case |
| Gas build limits | Base | −10% (combined cycle and combustion turbine) | Base |
| Demand | Base | Base | Low case, all four RTOs |
| Capacity Expansion Reliability Margin (PJM and MISO) | Base | Base | 6% wider |
Central Scenario
The Central Scenario is Modo Energy’s view of the most likely path for the Eastern Interconnection. Every lever sits at its base setting, and the other two scenarios are described as deviations from this case.
Commodity prices follow the EIA Annual Energy Outlook reference case. New-build costs track the NREL Annual Technology Baseline (ATB) Moderate trajectory for generation technologies, with storage on its own Advanced trajectory in every scenario, and each RTO runs on its published base load forecast. Policy is modelled as current law, with no anticipated changes to state or federal programs.
High Renewables
High Renewables accelerates the buildout of renewable capacity. Renewable capital costs fall on the aggressive NREL ATB Advanced trajectory, while gas and coal capital costs hold at Moderate. Gas and coal fuel prices sit 10% above the Central Scenario, raising the marginal cost of the thermal fleet.
Tighter siting and permitting also cut the annual build ceilings for combined cycle and combustion turbine capacity by 10%. In some regions and years, the ceiling limits gas build before cost does. Coal is excluded from the cut, because its existing build limits already rule out new capacity.
Cheaper renewables and costlier, more constrained gas combine to pull solar and storage forward across the interconnection. Solar additions rise from 171.6 GW in the Central Scenario to 234.3 GW, and battery additions from 47.9 GW to 56.8 GW. Battery additions track each other closely through the mid-2030s, while solar runs 10% to 20% ahead in High Renewables from the early 2030s. In both cases most of the divergence arrives after 2035, once the cheaper cost trajectory has compounded and the gas ceiling begins to bind.
Low Demand
Low Demand assumes load growth substantially undershoots the current outlook. Large-load and data-center projects largely fail to materialize, and vehicle and building electrification arrives more slowly. Technology costs and fuel prices hold at their Central Scenario settings.
Two RTOs, NYISO and MISO, publish a low demand case, and the model runs each on its own. ISO-NE and PJM publish none, so the model applies the reductions implied by NYISO’s and MISO’s cases, respectively, to their forecasts. The four legs therefore reach comparable totals by different mechanisms. NYISO’s Lower Demand Scenario concentrates its reduction in large loads, vehicle electrification, and building electrification, leaving a near-flat base load largely unchanged. MISO’s Long Term Load Forecast Low Trajectory pairs a flat percentage reduction to data-center load with a broad commercial, industrial, and residential slowdown. ISO-NE scales its CELT components by the ratio NYISO’s case implies for the matching component, separately for energy, summer peak, and winter peak. PJM splits its forecast into the published large-load adjustment and the base beneath it, then applies MISO’s datacenter and non-datacenter ratios to the two pieces.
Peak load falls in every RTO, and the gap widens over the forecast horizon rather than stepping down at once. By 2035, peak is 13.3% below the Central Scenario in PJM, 11.6% in MISO, 10.2% in NYISO, and 6.1% in ISO-NE. By 2049 those gaps reach 19.7%, 20.6%, 17.3%, and 17.4%. NYISO’s low case runs close to flat until the late 2030s, because the demand it removes is concentrated in large loads and electrification that the baseline forecast expects to arrive later.
In PJM and MISO, a particularly large cut falls on large-load and data-center projects that have not yet been built and could still arrive. That portion carries wider uncertainty per MW of peak than a general slowdown would, so the capacity expansion reliability margin in both RTOs is held 6% wider than a one-for-one rescaling of peak load would give, setting the capacity-scarcity signal that modelled investment responds to.
Revenue opportunities per scenario
Each scenario builds a different fleet, and that fleet shapes the prices a battery can capture. The four-hour top-bottom (TB4) spread measures the annual revenue available to a four-hour battery from the daily gap between the highest and lowest prices, summed across the year.
High Renewables is the strongest revenue environment in every ISO. Heavier solar buildout deepens midday price troughs, widening the intraday swing that storage captures. Gas and coal prices above the Central Scenario raise the marginal cost of the thermal fleet that still sets price in most hours, lifting evening peaks. Average energy prices rise alongside spreads. That rise comes from the commodity price lever, not from the cost of renewables.
Low Demand is the weakest environment, and it compresses price levels further than it compresses spreads. Capacity revenue moves furthest between scenarios. A smaller peak requires less firm capacity, and the capacity price falls faster than the energy price as a result.