2.8 Unit-Commitment Model
The US-REGEN electric model incorporates a relatively simple model of dispatch that excludes several operational costs and constraints such as ramping and minimum load levels due to the high computational cost of including them in an inter-temporal perfect foresight model. In recognition of these limitations, a standalone unit commitment (UC) version of the US-REGEN electric model has been developed to better understand the short-run costs and engineering challenges of operating the different capacity mixes output from the US-REGEN dynamic model. This model runs separately from the full US-REGEN model and does not iterate with the end-use model.
This UC version of the model solves for most units in a region for all hours in a single year, given a fixed capacity mix. It determines commitment and dispatch states for individual units, with the objective of minimizing operating costs, while accounting for technical system constraints and chronological operations. The goal of this approach is to integrate the capacity planning perspective (i.e., examining long-run investment decisions) with a UC and economic dispatch one (i.e., understanding the short-run costs and engineering challenges of operating different capacity mixes). This framework provides a test bed for assessing flexibility needs in the context of endogenous investments and regional heterogeneity.
The UC model determines the startup, shutdown, and operating schedule (including unit-specific output levels) for every unit during each hour of an annual time horizon. Combining economic dispatch with UC constraints results in a mixed-integer optimization problem with the objective of minimizing total system operating costs. The four primary cost elements in this objective function are variable O&M costs, fuel costs (with output-dependent heat rates), startup costs, and shutdown costs. The model accounts for multiple constraints, including a load balance condition for each region, maximum and minimum output levels for each unit, transmission constraints, optional operating reserve requirements, startup and shutdown logic for generators, minimum up and down times, and maximum ramp rates. Fuel use characteristics and emissions are a function of unit-specific output levels.
The UC model retains individual unit detail for a majority of the fleet in the region of interest. Decision variables related to operation are indexed over the set of all units in the US-REGEN region greater than 40 MW. Since intra-regional transmission is not modeled, variable generation resources across a model region are aggregated by their capacity types and dispatched as blocks. Wind and solar technologies can be curtailed during periods of over-generation.
Given the significance of transmission and trade in influencing electricity market outcomes, a novel feature of the US-REGEN UC model is its endogenous treatment of imports and exports. Trade may be an important flexibility resource to facilitate the exchange of electricity across regions during periods of surpluses or deficits, especially as intermittent resources comprise a greater fraction of generation and regional electricity markets become more tightly integrated. However, most UC models make simplifying assumptions about imports and exports, often assuming that future trade flows will mimic historical patterns. US-REGEN's integrated perspective models many regions at once to capture the increasingly interconnected landscape for system balancing. Cross-border flows are restricted by net transfer capacities, which are influenced by transmission investments in the dynamic model. To make the UC model of the entire US computationally tractable, US-REGEN has individual unit detail in the region of interest but aggregates units into capacity blocks for all other US regions. This formulation endogenously determines price-responsive trade positions.
Full documentation for the unit commitment version of US-REGEN is maintained separately (EPRI, 2015).