Production cost models (PCM) are used to understand how different hydrologic conditions and the corresponding impact on hydropower resource capabilities affects electric system schedules, prices, and overall performance. However, PCMs are traditionally limited by static parameterization of hydropower resource capabilities that fails to represent important details such as cascading reservoir dynamics, the nonlinear dependency of power production on reservoir head and water releases, and water system management constraints that guide water release schedules for environmental, hazard, and other requirements.
PCMs simulate the scheduling of electrical generation to meet load (demand) by solving a series of sequential optimization problems to balance generation and load at least cost, subject to the operational limitations and operational costs of generators and other system constraints (e.g. transmission).
In a PCM, each problem is simulated in sequence of successive scheduling windows and initializing each problem with results obtained from previous solutions. In a typical day-ahead scheduling simulation each problem will include 48 1-hour periods, and it will be incremented by 24 hours to represent subsequent problems, and the results of the first 24 hours of each problem are used to inform the initial conditions of the next problem.
Hydropower reservoir representation for the Western United States is typically limited to monthly hydropower production. This representation is likely to be inadequate as the amount of renewable generation on the grid increases and fossil units retire—leaving hydropower as one the few remaining sources of fully dispatchable generation.
In this new paradigm, it is critical that hydropower be accurately represented in production cost models. The overarching objective of this work is to improve the representation of hydropower in production cost models to address energy sector operational and planning questions.