Generation

How generation capacities and output are modeled across WECC

Capacity buildout

Description

Modo Energy’s capacity expansion model decides capacity additions on techno-economic grounds. Build limits for each technology come from the interconnection queue, each node’s build history and its forecast peak load.

Retirements follow publicly announced shutdowns where available. Otherwise, they follow technology-specific lifespans, based on the EIA-860 generator inventory and the WECC ADS generator list.

Forecast

Policy drivers

• California’s SB 100 requires 100% clean electricity by 2045
• Storage mandates and procurement targets drive battery buildout: CAISO’s BESS fleet grows from 24 GW in 2027 to 64 GW by 2050
• Once-through cooling regulations are driving thermal plant retirements

Assumptions and caveats

• Build decisions are informed by the Capacity Expansion Model and queue analysis

Data sources

Short-run marginal costs

Description

Short-run marginal costs (SRMCs) are estimated for all generation technologies in the system, including thermal and renewable assets. These values are derived primarily from fuel prices and heat rate assumptions. Gas prices follow Henry Hub plus each node’s delivered-gas premium from EIA-923. Henry Hub uses the CME futures strip in the near term, fading into the EIA Annual Energy Outlook (AEO) 2026. Coal, oil and uranium prices follow the CPUC SERVM commodity forecasts. Heat rates are calculated from EIA-923 fuel receipts and WECC ADS thermal IO curves. Carbon costs are incorporated using California and Washington allowance prices, described on the Capacity Expansion Model page. Where available, commodity prices, start costs, and outages are calculated on a plant-specific basis.

For variable renewable technologies such as wind and solar, SRMCs are adjusted to reflect tax credits, which can result in negative marginal costs.

Each node’s delivered-gas premium over Henry Hub is calibrated from 2025 EIA-923 fuel receipts by calendar month, so the premium keeps its seasonal shape in every forecast year. Nodes with no reported gas receipts take the average premium of the other nodes in their EIA sub-region. To 2030, California gas sits above Henry Hub, while the Northwest and Southwest buy below it, most of all in spring and autumn.

Policy drivers

• Production tax credits (PTC) and investment tax credits (ITC) for wind and solar are reflected in SRMCs.

Assumptions and caveats

• Technology-average heat rates are used for future or unbuilt units.

Data sources

Start costs

Description

Startup costs are modeled for thermal technologies that require discrete commitment decisions. Nuclear, solar, wind, and storage are assumed to be continuously available and do not incur startup costs in the model.

Start cost values are derived from WECC ADS thermal curves and EIA-923 fuel receipts, imputed using forecast commodity prices to estimate time-varying startup costs.

Assumptions and caveats

• Startup costs are only applied to technologies that require explicit unit commitment.
• No modeling of hot vs. cold start cost differences.

Data sources

Renewable capacity factors and outages

Description

Both load factors and outages profiles are modeled using CPUC SERVM capacity factors and WECC ADS hourly profiles. Each generator’s available capacity is expressed as a percentage of its nameplate capacity to calculate an empirical load factor. Nuclear outage factors are derived from NRC power status data.

For existing wind and solar generators, this observed load factor is held constant throughout the forecast horizon. New build generators are assigned load factors based on the regional average for the same technology class.

Assumptions and caveats

• Load factors and outages rates are based on a historical weather year and do not evolve over time.
• New builds inherit regional average load factors for their technology class.

Data sources