Flexibility in power systems is the potential to increase or decrease generation relative to scheduled generation or when most valuable. Increased penetration of variable renewable energy sources such as wind and solar increases the need for flexibility. Conventional hydropower plants are an important source of flexibility due to their ability to shut down and start generation units at short notice. However, there are not metrics or standards for hydropower managers to measure or quantify the potential flexibility of their systems. This novel study identifies key hydro system characteristics—physical and operational factors as well as the power markets—that, in our experience with real hydro systems, affect flexibility. A realistic but fictional system is analyzed that includes operating policies, deployment of reserves, physical aspects such as size of reservoirs, network configuration and power markets. The system is first modeled per “business as usual” operating rules to maximize total economic value of generation. The flexibility analysis measures the generation that can be increased or decreased in a single day by either maximizing the total on-peak generation in the upward direction or minimizing the total nadir generation in the downward direction. Results show the effects of each factor on both upward and downward flexibility.

Production cost models (PCMs) simulate dispatch of generators across a large power grid and are used widely by planners to study the reliability of electricity supply. As energy systems transition away from the thermoelectric technologies that have traditionally balanced electricity supply and demand, hydropower and its representation in PCMs is of increasing importance. A limitation of PCMs applied to continental power grids with diverse generation portfolios is that hydropower generation is simulated without full consideration of complex river dynamics, leading to possible misrepresentation of grid flexibility and performance. In addition, data used in PCMs may reflect outdated operating policies. In this paper we propose a hydropower generation feasibility test for PCMs. The approach uses a detailed hydropower model to determine whether the hourly hydropower schedule from a PCM with simplified monthly parameterization can be attained after accounting for realistic river dynamics and operating policies, such as spill requirements and general water movement and balance through a cascade reservoir system. We perform this hydropower generation test for the ‘Big 10’ hydropower system on the Columbia River (part of the Western Interconnect of the United States), revealing 9% overestimation of available hydropower generation in a PCM solution in an average hydrologic year. Our evaluation provides insight on the cost and opportunities for better representing hydropower in PCMs.